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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 15, 1999
REGISTRATION NO. 333-85955
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 1
TO
FORM S-1/S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
APPALACHIAN NATURAL GAS TRUST
(Exact name of registrant as specified in its charter)
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<S> <C> <C>
DELAWARE 1311 75-6550504
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)
</TABLE>
BANK ONE TEXAS, N.A.
500 THROCKMORTON, SUITE 801
FORT WORTH, TEXAS 76102
(817) 884-4417
ATTN: CORPORATE TRUST DEPARTMENT
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
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EASTERN STATES OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
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<S> <C> <C>
DELAWARE 1311 61-1093943
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)
</TABLE>
2800 EISENHOWER AVENUE
ALEXANDRIA, VIRGINIA 22314
(703) 317-2300
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
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AS TO BOTH REGISTRANTS:
CLIFTON A. BROWN
PRESIDENT AND CHIEF EXECUTIVE OFFICER
2800 EISENHOWER AVENUE
ALEXANDRIA, VIRGINIA 22314
(703) 317-2300
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
Copies to:
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ANDREWS & KURTH L.L.P. BAKER & BOTTS, L.L.P.
600 TRAVIS, SUITE 4200 ONE SHELL PLAZA
HOUSTON, TEXAS 77002 910 LOUISIANA
(713) 220-4200 HOUSTON, TEXAS 77002
ATTN: G. MICHAEL O'LEARY (713) 229-1234
ATTN: JOSHUA DAVIDSON
</TABLE>
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, please check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
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CALCULATION OF REGISTRATION FEE
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<S> <C> <C>
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PROPOSED MAXIMUM
AGGREGATE AMOUNT OF
TITLE OF EACH CLASS OF SECURITIES TO BE REGISTERED OFFERING PRICE(1)(2) REGISTRATION FEE
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Units of beneficial interests............................... $190,181,250 $52,871(3)
</TABLE>
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(1) Includes trust units issuable upon exercise of the underwriters'
over-allotment option.
(2) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(o).
(3) A portion of this filing fee, $50,040, was previously paid in connection
with the initial filing of this registration statement on August 26, 1999.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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<PAGE> 2
THE INFORMATION IN THIS PRELIMINARY PROSPECTUS IS NOT COMPLETE AND MAY BE
CHANGED. THESE SECURITIES MAY NOT BE SOLD UNTIL THE REGISTRATION STATEMENT FILED
WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PRELIMINARY
PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN
OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.
Subject to Completion, dated October 15, 1999
PROSPECTUS
APPALACHIAN NATURAL GAS TRUST
7,875,000 TRUST UNITS
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This is an initial public offering of units of beneficial interest in the
Appalachian Natural Gas Trust. Eastern States Oil & Gas, Inc., an indirect
wholly owned subsidiary of Statoil Energy Inc., has formed the trust and is
offering all of the trust units to be sold in this offering. Eastern States will
receive all proceeds from the offering. The trust will not receive any proceeds
from the offering. Eastern States will continue to own 2,625,000 trust units
after this offering, or 1,443,750 trust units if the underwriters'
over-allotment option is exercised in full.
Prior to this offering there has been no public market for the trust units.
Eastern States expects that the offering price will be between $19.00 and $21.00
per trust unit. Eastern States has applied to have the trust units listed on the
New York Stock Exchange under the symbol "ANG."
THE TRUST UNITS. Trust units are units of beneficial ownership of the trust
and represent undivided beneficial interests in the assets of the trust.
They do not represent any interest in Eastern States or Statoil Energy.
THE TRUST. The trust owns net profits interests in natural gas producing
properties located in the Appalachian Basin area of Kentucky and West
Virginia. The net profits interests entitle the trust to receive:
- 80% of Eastern States' net proceeds from the sale of the production from
2,471 producing wells; and
- 10% of Eastern States' net proceeds from the sale of the production from
all wells drilled on or after September 1, 1999 on the leases in Kentucky
and West Virginia that are subject to the net profits interest.
THE TRUST UNITHOLDERS. As a trust unitholder, you will receive quarterly
distributions of cash that the trust receives attributable to its net
profits interests from the sale of natural gas produced from the underlying
properties.
INVESTING IN THE TRUST UNITS INVOLVES RISKS. RISK FACTORS BEGIN ON PAGE 16.
<TABLE>
<CAPTION>
PER TRUST UNIT TOTAL
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<S> <C> <C>
Public offering price............................ $ $
Underwriting discount............................ $ $
Proceeds, before expenses, to Eastern States..... $ $
</TABLE>
Eastern States has also granted the underwriters the right to purchase up
to an additional 1,181,250 trust units at the initial public offering price less
the underwriting discount to cover over-allotments.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS ACCURATE OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
Lehman Brothers expects to deliver the trust units on or about
, 1999.
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JOINT BOOK-RUNNING MANAGERS
LEHMAN BROTHERS SALOMON SMITH BARNEY
CO-LEAD MANAGER
PAINEWEBBER INCORPORATED
CIBC WORLD MARKETS
CREDIT SUISSE FIRST BOSTON
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
DONALDSON LUFKIN & JENRETTE
A.G. EDWARDS & SONS, INC.
MCDONALD INVESTMENTS INC.
, 1999
<PAGE> 3
[MAP OF UNDERLYING PROPERTIES APPEARS HERE]
No dealer, salesperson or other person is authorized to give any
information or to represent anything not contained in this prospectus. You must
not rely on any unauthorized information or representations. This prospectus is
an offer to sell the trust units offered hereby, but only under circumstances
and in jurisdictions where it is lawful to do so. The information contained in
this prospectus is current only as of its date.
Through and including , 1999 (the 25th day after the date of
this prospectus), all dealers effecting transactions in these securities,
whether or not participating in this offering, may be required to deliver a
prospectus. This is in addition to a dealer's obligation to deliver a prospectus
when acting as an underwriter and with respect to an unsold allotment or
subscription.
i
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TABLE OF CONTENTS
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Prospectus Summary.......................................... 1
Risk Factors................................................ 16
Forward-Looking Statements.................................. 23
Use of Proceeds............................................. 23
Eastern States.............................................. 24
The Trust................................................... 25
Projected Year 2000 Distributable Cash...................... 25
The Underlying Properties................................... 34
Computation of Net Proceeds................................. 51
Federal Income Tax Consequences............................. 54
State Tax Considerations.................................... 58
ERISA Considerations........................................ 60
Description of the Trust Agreement.......................... 60
Description of the Trust Units.............................. 65
Underwriting................................................ 68
Selling Trust Unitholder.................................... 70
Validity of the Trust Units................................. 70
Experts..................................................... 71
Available Information....................................... 71
Glossary of Oil and Natural Gas Terms....................... 72
Index to Financial Statements............................... F-1
Information About Eastern States Oil & Gas, Inc. ........... A-1
Index to Financial Statements of Eastern States Oil & Gas,
Inc. ..................................................... AF-1
Ryder Scott Company, L.P. Reserve Report for the Underlying
Properties................................................ XA-1
Ryder Scott Company, L.P. Reserve Report for the Net Profits
Interest.................................................. XB-1
</TABLE>
ii
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PROSPECTUS SUMMARY
This summary may not contain all of the information that is important to
you. To understand this offering fully, you should read the entire prospectus
carefully, including the risk factors and the financial statements and notes to
those statements. You will find definitions for terms relating to the oil and
natural gas business in "Glossary of Oil and Natural Gas Terms." Ryder Scott
Company, L.P., an independent engineering firm, estimated the proved natural gas
reserves at August 31, 1999 for the underlying properties and the trust's net
profits interests included in this prospectus. Copies of their reserve reports
as of August 31, 1999 are located at the back of this prospectus as Exhibits A
and B. Historically, more than 99% of production from the underlying properties
has been natural gas and less than 1% has been oil. The net profits interests
conveyed to the trust will also include net proceeds from the sale of oil
production from the underlying properties. For purposes of this prospectus,
Eastern States uses the phrase "sale of natural gas from the underlying
properties" to also include the sale of oil from the underlying properties.
APPALACHIAN NATURAL GAS TRUST
Appalachian Natural Gas Trust was formed in August 1999 by Eastern States
under the Delaware Business Trust Act. Eastern States is the largest owner of
proved natural gas reserves, and believes it is one of the lowest cost
producers, in the Appalachian Basin. Eastern States is a wholly owned subsidiary
of Statoil Energy. Statoil Energy owns and operates power plants in the
northeast and mid-Atlantic regions of the United States, is a leading trader of
wholesale electricity and natural gas and specializes in providing a broad range
of energy and risk management services involving the delivery of natural gas,
electricity and alternative fuels to large industrial, institutional and
commercial customers.
Eastern States will transfer to the trust, as of September 1, 1999, an 80%
net profits interest in 2,471 producing natural gas wells in Kentucky and West
Virginia and a 10% net profits interest in wells drilled on or after September
1, 1999 on substantially all of Eastern States oil and gas leasehold interests
in Kentucky and West Virginia. Eastern States' interests in the 2,471 producing
wells that will be subject to and burdened by the 80% net profits interests are
referred to as the 2,471 underlying wells or the underlying wells. Eastern
States' interests in the oil and gas leases that will be subject to and burdened
by the 10% net profits interest are referred to as the underlying leases. The
underlying leases contain 1,528 proved undeveloped drilling locations. The
underlying wells and the underlying leases are collectively referred to as the
underlying properties. The underlying properties will not include any properties
or interests acquired by Eastern States on or after September 1, 1999.
The net profits interests entitle the trust to receive 80% of the net
proceeds received by Eastern States from the sale of natural gas from the
underlying wells and 10% of the net proceeds received by Eastern States from the
sale of natural gas from wells drilled on the underlying leases on or after
September 1, 1999. Net proceeds generally means cash received from the sale of
production from the underlying properties after deducting property and
production taxes, production costs, gathering and compression charges,
development costs and administrative and drilling overhead attributable to the
underlying properties. The net profits interests will be calculated separately
for Kentucky and West Virginia. The first distribution will be paid to
unitholders of record as of December 15, 1999 on or before December 25, 1999 for
the production period September 1, 1999 through September 30, 1999. For a more
complete description of the computation of net proceeds payable to the trust,
see "Computation of Net Proceeds" that begins on page 51.
Net proceeds payable to the trust depend upon production quantities, sales
prices of natural gas and costs to develop, produce, transport and market the
natural gas. If for any quarter aggregate costs should exceed gross proceeds,
the trust unitholders would not receive any cash distributions until future net
proceeds exceed the total of those excess costs, plus interest at the prime
rate. The trust will not be required to repay amounts to Eastern States;
instead, any amounts due to Eastern States will be deducted in calculating
future net proceeds payable to the trust.
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The underlying wells are characterized by a relatively high
reserve-to-production index of 21 years and a low expected production decline
rate averaging 5.5% for the initial five-year period following this offering. If
successful, Eastern States' planned development program is expected to reduce
this decline rate to an average of 3%.
Reserves in the Appalachian Basin typically have a high degree of step-out
development success, that is, as development progresses, reserves from newly
completed wells are reclassified from the proved undeveloped to the proved
developed category and additional adjacent locations are added to proved
undeveloped reserves. As a result, the amount of total proved reserves tends to
increase as development progresses.
Eastern States operates all of the 2,471 underlying wells and intends to
operate all or substantially all of the wells drilled on the underlying leases
on or after September 1, 1999. Eastern States has an average net revenue
interest of 87% and an average working interest of 97% in the properties
burdened by the trust's net profits interests. This large percentage working
interest provides for significant control over the timing and amount of
expenditures. Eastern States believes that its operation of more than 4,700
wells and 3,200 miles of gathering pipeline in Kentucky and West Virginia
provides it with regional economies of scale and a competitive advantage since
it is able to maintain low production costs relative to other producers in the
Appalachian Basin. In addition, the coordination of Eastern States' development
program in these states is facilitated by the integrated nature of its
production, pipeline and undeveloped leasehold positions.
Eastern States will market the natural gas produced from the underlying
properties and attempt to obtain the best prices available to it in the
marketplace. Generally, natural gas produced from the underlying properties will
be sold under existing contracts that have market-based pricing terms.
Currently, approximately 90% of natural gas produced by Eastern States is sold
under existing short-term contracts with its affiliate, Statoil Energy Services,
Inc., and affiliates of CNG Transmission Corp. For the eight month period ending
August 31, 1999, approximately 68% of the natural gas produced by Eastern States
was sold to Statoil Energy Services and approximately 22% was sold to affiliates
of CNG Transmission. The remaining natural gas is sold to numerous purchasers
generally at market-based prices.
Eastern States has experienced a temporary reduction in its delivery of
natural gas as a result of a shutdown of a third-party pipeline delivery system
for replacement of a portion of its pipeline system. The temporary shutdown,
which commenced September 27, 1999 and is expected to last through November 15,
1999, affects approximately 30% of Eastern States production in Kentucky, most
of which is attributable to the underlying wells. As a result of this shutdown,
the revenues attributable to the underlying wells for the fourth quarter of 1999
will be reduced, which in turn will reduce the amount of net proceeds payable to
the trust.
Eastern States has agreed, for the benefit of the trust, to hedge the sales
price payable for year 2000 production attributable to the net profits
interests. Under the hedge agreement, if the monthly closing NYMEX price in any
month of year 2000 is less than $ per MMbtu, Eastern States will pay the
trust an amount for the trust's share of that month's production based upon the
excess of $ per MMbtu over that monthly closing NYMEX price. If the monthly
closing NYMEX price in any month of the year 2000 exceeds $ per MMbtu,
Eastern States will retain from the net proceeds payable to the trust an amount
for the trust's share of that month's production based upon that excess. The
effect of this so called "collar" arrangement is that for year 2000 production
the net proceeds payable to the trust will be calculated, and the distributable
cash of the trust will be based, upon a "floor" price of $ per MMbtu and a
"ceiling" price of $ per MMbtu even if the prevailing monthly closing NYMEX
price is less than the "floor" price or more than the "ceiling" price. After the
year 2000, the price payable for production attributable to the net profits
interests will be a variable price not subject to a hedge agreement and may be
less than the $ per MMbtu "floor" price, or more than $ per MMbtu
"ceiling" price, specified under the hedge agreement.
2
<PAGE> 7
Statoil Energy is a U.S. subsidiary of the Norwegian state oil company "den
norske stats oljeselskap a.s," which is also known as The Statoil Group. As
described under the caption "Eastern States," The Statoil Group has decided to
pursue a sale of its ownership in Statoil Energy. None of The Statoil Group,
Statoil Energy or Eastern States can assure you that
- this sale will be made,
- if so made, when this sale will be made or,
- if so made, that it will not adversely affect Eastern States or its
ability to operate and develop the underlying properties as contemplated
herein.
On federal income tax returns, investors will be required to include their
proportionate share of trust net income. Investors will also be entitled to
claim a depletion deduction relating to production from the underlying
properties. Because payments to the trust will be generated by depleting assets,
a portion of each distribution may represent a return of your original
investment rather than a return on your original investment. The deductions will
permit investors to defer or reduce taxes on a significant portion of the income
recognized as a result of owning an interest in the trust.
3
<PAGE> 8
EASTERN STATES' OWNERSHIP INTERESTS ARE ALIGNED WITH THE UNITHOLDERS
Eastern States' retained interest in the underlying properties entitles it
to 20% of the net proceeds from the sale of production from the 2,471 underlying
wells and 90% of the net proceeds from the sale of production from wells drilled
on the underlying leases on or after September 1, 1999.
Eastern States will also own up to 25% of the outstanding trust units.
Eastern States believes that its retained direct ownership interest in the
underlying properties, as well as the retained trust units, provides it with
sufficient economic incentives to continue to operate and develop the underlying
properties in an efficient and cost-effective manner. Eastern States is under no
obligation to continue to own the underlying properties. If Eastern States
disposes of a substantial portion of these retained interests, its economic
incentive to continue to operate and develop the underlying properties would
decline.
The following chart shows the relationship of The Statoil Group, Statoil
Energy, Eastern States, the underlying properties, the trust and the public
trust unitholders, assuming no exercise of the underwriters' over-allotment
option.
CHART
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(a) The Statoil Group holds its 99.9% interest in Statoil Energy through a
wholly owned subsidiary, Statoil Energy Holdings, Inc. As described under
the caption "Eastern States," The Statoil Group has decided to pursue a sale
of its ownership in Statoil Energy.
(b) If the underwriters' over-allotment option is exercised in full,
approximately 86% of the trust units will be owned by the public unitholders
and Eastern States will retain the remaining 14% of the trust units.
4
<PAGE> 9
THE UNDERLYING PROPERTIES
The underlying properties are located in the Appalachian Basin, which is
the oldest and geographically one of the largest natural gas producing regions
in the United States. As of August 31, 1999, Ryder Scott estimated the proved
developed reserves of the 2,471 underlying wells to be 331 Bcfe, with future net
cash flows discounted at 10% before income taxes of approximately $265 million.
Approximately 65% of the future net discounted cash flows before income taxes
are represented by proved developed reserves located in West Virginia and
approximately 35% of the future net discounted cash flows before income taxes
are represented by proved developed reserves located in Kentucky. As of August
31, 1999, Ryder Scott estimated proved undeveloped reserves for the underlying
leases to be 437 Bcfe.
The areas in which the underlying properties are located are characterized
by wells with comparably low rates of annual decline in production, low
production costs and high Btu, or energy, content. Once drilled and completed,
wells in the Appalachian Basin typically have low ongoing operating and
maintenance requirements and minimal capital expenditures. Wells in these areas
have been producing for many years, in some cases since the early 1900's.
Reserve estimates for properties with long production histories are generally
more reliable than estimates for properties with shorter histories.
Substantially all of the underlying wells are relatively shallow, with
depths ranging from 1,000 to 7,000 feet below the surface. Many of the
underlying wells are completed in more than one producing zone and production
from these zones may be mixed or commingled. Commingled production lowers
producing costs on a per unit basis compared to isolated zone completions.
Eastern States' transfers to the trust of net profits interests in the
underlying wells in Kentucky and West Virginia are intended to create a
diversity of well profiles and a diversity of value. The well with the highest
discounted net present value in the Ryder Scott reserve report represents less
than 0.5% of the value of all underlying wells. The inclusion of a large number
of future drilling opportunities on approximately 1.2 million gross acres
comprising the underlying leases, excluding the Rome exploration area but before
giving effect to the other excluded interests described in the two paragraphs
below, along with the underlying wells will provide statistical and geological
diversity in multiple potential producing horizons in Kentucky and West
Virginia.
Eastern States currently owns approximately 4,700 producing wells in
Kentucky and West Virginia. The 2,471 producing wells that constitute the
underlying wells do not include wells in Kentucky and West Virginia with any of
the following characteristics:
- wells owned by a financial institution that are Section 29 production
payment properties and most of which are operated by Eastern States;
- wells drilled during the 20 months ended August 31, 1999, each of which
has a limited production history and a relatively high decline profile;
- wells with high operating costs;
- marginal producing wells and associated leases;
- wells and associated leases with title or consent issues; and
- wells in which Eastern States is not the operator.
The underlying leases do not include leases and interests in Kentucky and
West Virginia with any of the following characteristics:
- leases and mineral interests in Kentucky pertaining to the Rome
exploration area, which is characterized by high exploration risk;
- the portion of leases which have been farmed out to third parties; and
- leases or interests with known transfer or title issues, including all
potential coalbed methane exploration and developmental rights.
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<PAGE> 10
PRODUCTION FROM THE UNDERLYING PROPERTIES RECEIVES PREMIUMS FOR LOCATION AND
HIGH ENERGY CONTENT
Natural gas produced in the Appalachian Basin has historically received a
premium over natural gas produced in other regions due to the region's close
proximity to the markets in the northeast United States. For the period 1991
through 1998, natural gas price indices for Appalachian Basin production have
averaged $0.25 per MMbtu more than prices for natural gas contracts traded on
the NYMEX for the delivery of natural gas at Henry Hub, Louisiana. During these
eight years, the average annual Appalachian Basin premium has ranged from $0.14
per MMbtu to $0.47 per MMbtu. The Appalachian Basin premium is typically lower
during warmer-than-normal winters, such as the previous two winters.
Natural gas sold from the underlying properties has historically received
an additional premium because of its higher Btu content. The average Btu content
for each cubic foot of natural gas produced from the underlying properties is
approximately 1,131, which has historically provided an average 13.1% premium
over the standard measure of 1,000 Btu per cubic foot when calculating realized
prices on a per Mcf basis.
Eastern States cannot provide any assurance that it will be able to realize
either of these premiums in the future.
LOW COST PRODUCER
Eastern States believes that it is a low cost producer. Based on the
contractual production costs to be charged by Eastern States on a per well basis
and based on the estimated production for the year 2000, Eastern States
estimates that production costs and taxes allocated to the trust in computing
net proceeds will be $0.48 per Mcfe during 2000. For public reporting companies
in the United States, the average production cost from 1996 through 1998 was
$0.61 per Mcfe. Eastern States cannot assure you that it will continue to be a
low cost producer.
LONG LIFE OF PROPERTIES
The productive lives of producing natural gas properties are often compared
using their reserve-to-production index. This index is calculated by dividing
total proved reserves of the property by annual production for the prior 12
months. The reserve-to-production index for the underlying properties at August
31, 1999 was approximately 21 years. This reserve-to-production index shows a
relatively long producing life compared to an average index of 8.8 years for
U.S. natural gas properties at year-end 1997. Because production rates naturally
decline over time, the reserve-to-production index may not be a useful estimate
of how long properties should economically produce. Based on the Ryder Scott
reserve report, production from the underlying properties is expected to
continue for at least 50 more years.
HIGH PERCENTAGE OF PROVED DEVELOPED RESERVES
Proved developed reserves are generally the lowest risk category of
reserves because their production requires no significant future development
costs and their production histories are established. Proved developed reserves
represent approximately 88% of the total proved reserves and 96% of the future
net discounted cash flow from the trust's net profits interests in the
underlying properties.
HISTORY OF LOW COST ADDITIONS TO PROVED RESERVES
Eastern States has a record of successfully adding reserves to the
underlying properties through development at costs which are generally less than
U.S. industry averages. Over the three years ended December 31, 1998, Eastern
States has added through development drilling approximately 97 Bcfe of proved
developed reserves at an average cost of $0.65 per Mcfe in Kentucky and West
Virginia. For public reporting companies in the United States, the average
industry cost of adding natural gas reserves from 1996 through 1998 was $0.76
per Mcfe. In addition, during 1997 and 1998, Eastern States had substantial
upward revisions of its proved undeveloped reserve estimates on the underlying
properties. Eastern States
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<PAGE> 11
cannot assure you that it will continue to be able to add proved reserves at a
lower cost than the industry average or that it will continue to have upward
revisions of its reserve estimates.
SIGNIFICANT INVENTORY OF DRILLING OPPORTUNITIES
Eastern States currently has an inventory of approximately 1.2 million
gross acres, excluding the Rome exploration area but before giving effect to the
other excluded interests, comprising the underlying leases, of which
approximately 74% have not been developed. As of August 31, 1999, Ryder Scott
estimated the proved undeveloped reserves of the underlying leases to be 437
Bcfe from 1,528 proved undeveloped drilling locations, with estimated future net
discounted cash flows of $102 million. Based upon current conditions, Eastern
States intends to drill an average of approximately 200 wells per year on the
underlying leases for at least the next five years. The trust will have a 10%
net profits interest in these wells. The development costs for drilling 200
wells, including drilling overhead, in the year 2000 is estimated to be
approximately $44 million, of which approximately $4.4 million will be
attributable to the net profits interest of the trust. Eastern States expects to
fund its development expenditures from internally generated cash flows from
existing properties. The level of development activity and the actual costs
incurred, however, will depend on results of prior development activities,
natural gas prices and the development cost in comparison to expected rates of
return, as well as the types of wells drilled and any unanticipated events. In
the last five years, Eastern States has completed approximately 98% of the wells
it has drilled in Kentucky and West Virginia.
Eastern States may face conflicts of interest in allocating its resources
between additional development of the underlying properties and development of
other oil and natural gas properties that it now owns or may own in the future.
Eastern States allocates resources for development based on expected rates of
return. The underlying properties have historically provided attractive rates of
return on development projects compared to Eastern States' other properties and
are expected to continue to do so in the future.
EFFECT OF PLANNED DEVELOPMENT PROGRAM
Without future development, the underlying wells would typically experience
a 5.5% annual decline in production for the initial five-year period following
this offering. Projected development expenditures for the underlying properties
included in the Ryder Scott reserve report, totaling $285 million through 2007
or $28.5 million net to the trust, are expected to reduce the natural rate of
decline in production to an average of 3% per year. If Eastern States drills and
completes new wells or conducts other development activities related to the
2,471 underlying wells, those activities should serve to offset, at least in
part, the natural production decline from the underlying wells. The trust will
benefit from increased production, net of 80% of the related development costs
of the 2,471 underlying wells and net of 10% of the related development costs of
new wells drilled on or after September 1, 1999 on the underlying leases.
Eastern States' development plan will differ from that reflected in the Ryder
Scott reserve report because Eastern States typically drills a number of
unproved locations each year.
ADDITIONAL DEVELOPMENT OPPORTUNITIES
Eastern States believes that the underlying properties may offer economic
development projects that are not included in its existing proved reserves. For
the period January 1, 1998 to August 31, 1999, approximately 40% of all wells
drilled by Eastern States were on locations classified as unproved at the time
of drilling. These additional development opportunities could add production and
proved reserves beyond those contained in the Ryder Scott reserve report.
Eastern States expects costs per Mcfe associated with reserves added
through additional development projects to be comparable to its historical costs
of reserve additions in Kentucky and West Virginia. Development costs will be
deducted from the net profits interests as they are incurred and will result in
lower quarterly distributions than would exist if these costs were not incurred.
Production increases from
7
<PAGE> 12
these projects may ultimately increase future distributions over what would have
been distributed had the development expenditures not been incurred. These
development opportunities include:
- drilling unproved locations;
- deepening existing wells in locations or into formations that are not
classified as proved reserves in the Ryder Scott reserve report;
- opening new producing zones in existing wells;
- recompletions;
- adding pipelines and compression to improve production flow or to reduce
third party gathering and compression charges; and
- performing mechanical and chemical treatments to stimulate production
rates.
These development activities will be primarily attributable to wells
drilled on the underlying leases that are subject to the 10% net profits
interest, but could be attributable to the 2,471 underlying wells that are
subject to the 80% net profits interest. For a description on whether
development activities will be attributable to the 10% net profits interest or
the 80% net profits interest, see "The Underlying Properties -- General."
PRO FORMA OPERATING MARGIN BEFORE DEVELOPMENT COSTS
The following is a discussion of the pro forma adjustments made to the
historical average net sales meter price after deducting third party gathering
and compression charges for the underlying properties for the year ended
December 31, 1998 and the eight months ended August 31, 1999 to arrive at a pro
forma operating margin. Except for the pro forma adjustments, the quantities and
amounts in this presentation are identical to those reported in the historical
financial statements for the underlying properties. For a further description of
these costs and charges, see "Computation of Net Proceeds -- Net Profits
Interests."
Eastern States' Gathering and Compression Costs. Eastern States' gathering
and compression costs consist of the following two components shown on two lines
in the table: actual costs incurred to gather, compress and process natural gas
produced from the underlying properties and an amount to reimburse Eastern
States for depreciation of the gathering and compression facilities and to
provide a reasonable return on investment in the facilities. Eastern States' pro
forma gathering and compression charges shown in the following table are the
actual costs incurred of $0.09 per Mcfe for the year ended December 31, 1998 and
$0.09 per Mcfe for the eight months ended August 31, 1999. The table also shows
a reimbursement for depreciation and return on investment of $0.14 per Mcfe for
the year ended December 31, 1998 and of $0.14 per Mcfe for the eight months
ended August 31, 1999. The reimbursement for depreciation and return on
investment have not been allocated in the past by Eastern States and Eastern
States used the same amount in calculating projected year 2000 distributable
cash.
Compressor Fuel and Line Loss. Eastern States' compressor fuel and line
loss shown in the following table reflects actual costs of $0.14 per Mcfe for
the year ended December 31, 1998 and $0.14 per Mcfe for the eight months ended
August 31, 1999. In the future, the amount of this charge will be based on
actual volumes consumed as fuel by Eastern States' compressors and actual
volumes lost by Eastern States during gathering and compression.
Production Costs. Except for wells completed below 7,000 feet, Eastern
States will deduct a monthly fixed production fee of $170 per well for wells
producing five or more Mcf per day and $70 per well for wells producing less
than five Mcf per day. For wells completed at depths below 7,000 feet, Eastern
States will deduct a monthly fixed production fee of $300 per well regardless of
daily production amounts. These charges will also apply to shut-in wells,
temporarily abandoned wells and other inactive wells. Prior to the closing of
this offering, Eastern States had actual direct production costs of $0.19 per
Mcfe for the year ended December 31, 1998 and $0.20 per Mcfe for the eight
months ended August 31, 1999 relating to the underlying properties. The pro
forma production costs are higher than actual costs in order to provide Eastern
States a reimbursement of $0.04 to $0.05 per Mcfe for depreciation and
amortization of its office expenditures, information systems and other
capitalized costs which are included in the fixed charges.
8
<PAGE> 13
Overhead. Prior to the closing of this offering, Eastern States has not
charged an overhead fee. The pro forma overhead expense represents a monthly fee
to be charged by Eastern States of $65 per well to reimburse Eastern States for
its general and administrative costs. This fee will continue to be charged in
the event a well is shut-in, temporarily abandoned or otherwise inactive.
Development Costs. Development costs are not included in the following
table since none of the wells drilled by Eastern States in the period January 1,
1998 through August 31, 1999 are included in the underlying properties because
of their limited production history and relatively high decline profile.
Development costs, including a drilling overhead fee of $36,000 for each well
drilled or deepened to another formation, zone or horizon on the underlying
properties after September 1, 1999, will be deducted in the future as Eastern
States incurs expenses to fund development of the underlying properties. This
amount will be proportionately reduced based on Eastern States' percentage
working interest on each well drilled on underlying properties, which currently
averages 97%. Eastern States expects to drill approximately 200 wells in the
year 2000 on the underlying leases resulting in development costs of
approximately $44 million, of which approximately $4.4 million will be
attributable to the net profits interests. Based on the Ryder Scott reserve
report for estimated production in the year 2000 of 13.6 Bcfe, this equates to
development costs of $0.32 per Mcfe.
<TABLE>
<CAPTION>
PRO FORMA
-------------------------------
YEAR ENDED EIGHT MONTHS
DECEMBER 31, ENDED AUGUST 31,
1998 1999
------------ ----------------
(PER MCFE) (PER MCFE)
<S> <C> <C>
Sales Price:
Average net sales meter price after deducting third
party gathering and compression charges............. $ 2.42 $ 2.36
Less Eastern States' gathering and compression
charges............................................. (0.09) (0.09)
Less pro forma reimbursement for depreciation and
return on investment................................ (0.14) (0.14)
Less Eastern States' compressor fuel cost and line
loss................................................ (0.14) (0.14)
------- -------
Pro forma average realized sales price................. 2.05 1.99
------- -------
Expenses:
Production costs....................................... 0.23 0.25
Production and property taxes.......................... 0.20 0.19
Overhead............................................... 0.10 0.10
Development costs...................................... -- --
------- -------
Total expenses................................. 0.53 0.54
------- -------
Operating margin......................................... $ 1.52 $ 1.45
======= =======
</TABLE>
PROVED RESERVES
Based on the Ryder Scott reserve report, proved reserves of the underlying
properties are over 99% natural gas. The following tables provide, as of August
31, 1999, estimated proved reserves of natural gas and natural gas equivalents,
and undiscounted and discounted estimated future net cash flows for the
underlying properties and the net profits interests. The estimates below were
prepared by Ryder Scott. Proved reserves in the tables below for the underlying
properties are based on natural gas and oil prices realized by Eastern States as
of August 31, 1999, which were $2.75 per Mcf of natural gas and $18.75 per Bbl
of oil. Proved reserves in the table below for the net profits interest are
based on prices of $2.61 per Mcf of natural gas and $18.75 per Bbl of oil. The
$2.61 price represents the $2.75 price realized by Eastern States less the $0.14
charge to the net profits interest for reimbursement for depreciation and a
return on Eastern States' investment in its gathering and compression systems,
which has not been charged by Eastern States prior to the closing of this
offering. Natural gas equivalents in the tables are the sum of the reserves for
natural gas and oil, calculated on the basis that one Bbl of oil is the energy
equivalent of six Mcf of natural gas. These amounts exclude unproved reserves
that Eastern States may develop in the
9
<PAGE> 14
future. The amounts of estimated future net cash flows from proved reserves
shown in the table are before income taxes. Discounted future net revenues are
based on a discount rate of 10%. Reserve estimates are subject to revision.
PROVED DEVELOPED RESERVES OF THE UNDERLYING PROPERTIES
AS OF AUGUST 31, 1999
<TABLE>
<CAPTION>
ESTIMATED FUTURE NET CASH
PROVED DEVELOPED RESERVES FLOWS FROM PROVED
---------------------------- DEVELOPED RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Underlying wells by district:
Brenton, West Virginia................... 85,397 85,397 $188,642 $ 70,194
Madison, West Virginia................... 79,114 79,155 155,303 61,034
Weston, West Virginia.................... 46,904 48,333 106,569 42,273
Pikeville, Kentucky...................... 118,166 118,254 270,963 91,360
------- ------- -------- --------
Total............................ 329,581 331,139 $721,477 $264,861
</TABLE>
PROVED UNDEVELOPED RESERVES OF THE UNDERLYING PROPERTIES
AS OF AUGUST 31, 1999
<TABLE>
<CAPTION>
ESTIMATED FUTURE NET CASH
PROVED UNDEVELOPED RESERVES FLOWS FROM PROVED
---------------------------- UNDEVELOPED RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Underlying leases by district:
Brenton, West Virginia................... 204,626 204,626 $350,763 $ 38,581
Madison, West Virginia................... 79,755 79,755 114,983 16,631
Weston, West Virginia.................... 11,158 11,158 17,612 1,727
Pikeville, Kentucky...................... 140,994 140,994 266,113 45,477
------- ------- -------- --------
Total............................ 436,533 436,533 $749,471 $102,416
</TABLE>
TOTAL PROVED RESERVES OF THE UNDERLYING PROPERTIES
AS OF AUGUST 31, 1999
<TABLE>
<CAPTION>
ESTIMATED FUTURE NET CASH
TOTAL PROVED RESERVES FLOWS FROM TOTAL PROVED
---------------------------- RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Underlying properties by district:
Brenton, West Virginia................... 290,023 290,023 $ 539,405 $108,775
Madison, West Virginia................... 158,869 158,910 270,286 77,665
Weston, West Virginia.................... 58,062 59,491 124,181 44,000
Pikeville, Kentucky...................... 259,160 259,248 537,076 136,837
------- ------- ---------- --------
Total............................ 766,114 767,672 $1,470,948 $367,277
</TABLE>
Proved reserves for the net profits interests attributable to the 2,471
underlying wells are calculated by subtracting from 80% of proved reserves,
reserve quantities of a sufficient value to pay 80% of the future estimated
production and development costs that are deducted in calculating net proceeds,
before overhead and trust administrative expenses. Proved reserves for the net
profits interests attributable to the proved undeveloped reserves owned by
Eastern States in Kentucky and West Virginia are calculated by subtracting from
10% of the proved undeveloped reserves, reserve quantities of a sufficient value
to pay 10% of the future estimated production and development costs that are
deducted in calculating net
10
<PAGE> 15
proceeds before overhead and trust administrative expenses. Approximately 67
Bcfe of proved reserves has been deducted to pay the future estimated production
and development costs for the underlying properties. As a result, proved
reserves for the net profits interests reflect quantities that are calculated
after reductions for future costs and expenses based on price and cost
assumptions used in the reserve estimates.
For the year 2000, production and property taxes of approximately $2.9
million have not been deducted in calculating reserve quantities attributable to
the net profits interests, but are reflected as costs in the reserve report.
For the year 2000, administrative overhead of the trust is expected to be
$1.5 million, the drilling overhead fee charged to the trust is expected to be
approximately $700,000 and trust administrative expenses are expected to be
approximately $300,000. These overhead and trust administrative expenses have
not been deducted in calculating reserve quantities attributable to the net
profits interests and are not reflected as costs in the reserve report.
PROVED RESERVES FOR THE NET PROFITS INTERESTS
AS OF AUGUST 31, 1999
<TABLE>
<CAPTION>
ESTIMATED FUTURE NET CASH
TOTAL PROVED RESERVES FLOWS FROM TOTAL
---------------------------- PROVED RESERVES
GAS EQUIVALENTS -------------------------
GAS (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED
---------- --------------- ------------ ----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C>
Underlying properties:
Net profits interests in underlying wells
(80%)...................................... 210,018 211,044 $507,436 $191,971
Net profits interests in underlying leases
(10%)...................................... 29,083 29,083 69,771 8,449
------- ------- -------- --------
Total net profits interest...................... 239,101 240,127 $577,207 $200,420
======= ======= ======== ========
Per trust unit (10,500,000 trust units)......... $ 54.97 $ 19.09
======== ========
</TABLE>
11
<PAGE> 16
HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES
The following table provides production and financial information relating
to the underlying properties for 1996, 1997 and 1998 and for each of the
eight-month periods ended August 31, 1998 and 1999. Eastern States did not own
all of the underlying properties for each of the periods indicated. The audited
statements of revenue and direct operating expenses of the underlying properties
for the years ended December 31, 1996, 1997 and 1998 and the unaudited
statements for each of the eight-month periods ended August 31, 1998 and 1999
begin on page F-3 in this prospectus. This table reflects only historical costs
and does not include the incremental costs and charges that will be deducted by
Eastern States in calculating net proceeds payable to the trust.
<TABLE>
<CAPTION>
EIGHT MONTHS
ENDED AUGUST 31,
-----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
($ IN THOUSANDS) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
Wellhead volumes:
Natural gas (MMcf)............................ 19,318 19,960 19,040 13,184 11,967
Oil (MBbls)................................... 35.1 30.6 20.4 12.9 18.9
Average realized sales prices:
Natural gas (per Mcf)......................... $ 2.84 $ 2.62 $ 2.20 $ 2.27 $ 2.14
Oil (per Bbl)................................. $ 19.29 $ 17.35 $ 11.86 $ 12.17 $ 12.17
Revenue:
Natural gas sales............................. $54,877 $52,303 $41,835 $29,879 $25,594
Oil sales..................................... 677 531 242 157 230
------- ------- ------- ------- -------
Total................................. 55,554 52,834 42,077 30,036 25,824
------- ------- ------- ------- -------
Direct operating expenses:
Production and property taxes................. 5,179 4,872 3,809 2,713 2,338
Production expenses........................... 6,300 5,106 3,603 2,401 2,401
------- ------- ------- ------- -------
Total................................. 11,479 9,978 7,412 5,114 4,739
------- ------- ------- ------- -------
Excess of revenues over direct operating
expenses...................................... $44,075 $42,856 $34,665 $24,922 $21,085
======= ======= ======= ======= =======
</TABLE>
YEAR 2000 PROJECTED DISTRIBUTABLE CASH
The following table provides a projection of trust distributable cash
related to estimated production for the twelve months ending December 31, 2000.
This projection assumes sales volumes and production and development costs
estimated by Ryder Scott. A copy of the Ryder Scott reserve report for the net
profits interests is included as Exhibit B to this prospectus.
Eastern States will market the natural gas produced from the underlying
properties and attempt to obtain the best prices available to it in the
marketplace. Generally, natural gas produced from the underlying properties will
be sold under existing contracts that have market-based pricing terms. For the
year 2000, however, Eastern States has entered into a hedge agreement for the
benefit of the trust. For a description of this hedge agreement, see "Projected
Year 2000 Distributable Cash -- Projected Year 2000 Distributable Cash" that
begins on page 26 below.
The calculations in the projection assume an average net wellhead price of
$ per Mcf of natural gas for year 2000 production, which is based on the
NYMEX mid-point under the hedge agreement, and oil prices of $18.00 per Bbl.
Eastern States has prepared this projection as its best estimate of trust
distributable cash for the year 2000, on an accrual or production basis, based
on these pricing assumptions and other assumptions that are described in
"Projected Year 2000 Distributable Cash -- Significant Assumptions Used to
Prepare the Projected Year 2000 Distributable Cash." Because the projections are
prepared on an accrual or production basis for the year 2000, the projections
represent an estimate of cash that would be distributed to unitholders on or
before June 25, 2000, September 25, 2000, December 25, 2000 and March 25, 2001.
The projections and the assumptions on which they are based are subject to
12
<PAGE> 17
significant uncertainties, many of which are beyond the control of Eastern
States or the trust. ACTUAL YEAR 2000 DISTRIBUTABLE CASH, THEREFORE, COULD VARY
SIGNIFICANTLY BASED UPON CHANGES IN ANY OF THESE ASSUMPTIONS.
Distributable cash is particularly sensitive to natural gas prices. See
"Projected Year 2000 Distributable Cash -- Sensitivity of Projected Year 2000
Distributable Cash to Natural Gas Prices" which shows estimated effects on
projected year 2000 distributable cash from changes in natural gas prices.
Accordingly, the projected year 2000 distributable cash is not necessarily
indicative of distributions for future years.
As a result of typical production declines for natural gas properties, and,
subject to the success of the drilling of development wells, production
estimates generally decrease from year to year. Due to the seasonal demand for
natural gas, the amount of distributable cash may vary on a seasonal basis. Cash
available for distribution may be subject to further seasonal variation since
the weather-related adjustment of drilling activity may result in higher capital
expenditures during the warmer period of the year, when historically lower
natural gas prices are realized. For example, in the year 2000, Eastern States
expects to drill on the underlying properties approximately 15 wells in the
first quarter, approximately 55 wells in the second quarter, approximately 80
wells in the third quarter and approximately 50 wells in the fourth quarter.
<TABLE>
<CAPTION>
PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTERESTS
---------------- ----------------- -----------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Underlying Properties
Volumes Produced:
Natural gas:
Gross production (MMcf)..................... 16,485 5,248 13,713
Less a 1% allowance for facilities
maintenance (MMcf)(a).................... (165) (53) (137)
------- -------- -------
Net production (MMcf)....................... 16,320 5,195 13,576
Oil:
Gross production (MBbls).................... 15.0 -- 12.0
Less a 1% allowance for facilities
maintenance (MBbls)...................... (0.2) -- (0.1)
------- -------- -------
Net production (MBbls)...................... 14.8 -- 11.9
Assumed Average Net Wellhead Sales Price:
Natural Gas (per Mcf)(b).................... $ 2.59 $ 2.59 $ 2.59
======= ======== =======
Oil (per Bbl)............................... $ 18.00 -- $ 18.00
======= ======== =======
</TABLE>
13
<PAGE> 18
<TABLE>
<CAPTION>
PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTERESTS
---------------- ----------------- -----------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Calculation of Distributable Cash
Revenues:
Natural gas sales............................. $42,236 $ 13,446 $35,134
Oil sales..................................... 267 -- 213
------- -------- -------
Total.................................... $42,503 $ 13,446 $35,347
------- -------- -------
Costs:
Production and property taxes................. 3,443 1,089 2,863
Production costs.............................. 4,510 302 3,639
Development costs and drilling overhead....... -- 44,249 4,425
Overhead...................................... 1,875 115 1,511
------- -------- -------
Total.................................... 9,828 45,755 12,438
------- -------- -------
Net proceeds.................................. 32,675 (32,309) 22,909
Net profits percentage........................ 80% 10%
------- -------- -------
Trust cash.................................... 26,140 (3,231) 22,909
Trust administrative expenses................. 300
=======
Trust distributable cash...................... $22,609
=======
Trust distributable cash per trust unit
(10,500,000 trust units).................... $ 2.15
=======
</TABLE>
<TABLE>
<CAPTION>
CASH DISTRIBUTION AS A PERCENTAGE OF
AMOUNT $20.00 TRUST UNIT PRICE
------ ------------------------------------
<S> <C> <C>
Per Trust Unit (10,500,000 trust units):
Total cash distributions (and taxable income before
depletion)......................................... $2.15 10.75%
Cost depletion tax deduction.......................... (0.91)
-----
Taxable income........................................ 1.24
Income tax rate(c).................................... 39.6%
-----
Income tax to unitholders............................. (0.49)
-----
Net cash distributions after tax to unitholders....... $1.66 8.30%
=====
</TABLE>
- ---------------
(a) The 1% facilities maintenance allowance provides for an estimated loss of
production volumes due to the periodic shutdown of gathering and
compression facilities, transmission pipelines or other production
equipment.
(b) For the adjustments made to result in an assumed average net wellhead price
of $2.59 per Mcf, see the table under the caption "Projected Year 2000
Distributable Cash" on page 27 of this prospectus.
(c) Assumes maximum federal effective tax rate applicable to individuals, but
does not take into account state income taxes that may be payable by
unitholders to Kentucky and West Virginia or their state of residence.
14
<PAGE> 19
THE OFFERING
Trust units offered by Eastern
States.......................... 7,875,000, or 9,056,250 if the underwriters'
over-allotment option is exercised in full.
Trust units outstanding......... 10,500,000 trust units will be issued and
outstanding upon the closing of this
offering, of which 2,625,000 trust units will
be owned by Eastern States. If the
underwriters' over-allotment option is
exercised in full, 1,443,750 of the trust
units will be owned by Eastern States.
Use of proceeds................. Eastern States will receive all the net
proceeds from this offering, which will be
used to repay a portion of its existing
indebtedness to Statoil Energy Holdings, Inc.
NYSE symbol..................... The trust has applied to list the trust units
on the New York Stock Exchange under the
symbol "ANG."
Sales price hedge for Year 2000
production.................... Eastern States has agreed to hedge the NYMEX
portion of the sales price payable for the
trust's share of year 2000 natural gas
production. Under this agreement, if the
monthly closing NYMEX price in any month
during year 2000 is less than a "floor" price
of $ per MMbtu or more than a "ceiling"
price of $ per MMbtu, net proceeds
payable to the trust for year 2000 gas
production will be calculated based upon the
"floor" price or "ceiling" price.
Conditional right of
repurchase...................... Eastern States will retain the right to
repurchase all, but not less than all, of the
outstanding units at any time if 15% or less
of the outstanding units are owned by persons
or entities other than Eastern States and its
affiliates. These repurchases will be made at
no less than the current market price.
Property trustee................ Bank One, Texas, N.A.
Delaware trustee................ Bank One Delaware, Inc.
INVESTING IN TRUST UNITS
Investing in the trust units differs from investing in corporate stock in
the following ways:
- trust unitholders are not owed a fiduciary duty by Eastern States, but
they are owed a fiduciary duty by the trustees of the trusts to the
extent provided in the trust agreement;
- trust unitholders have limited voting rights;
- trust unitholders are taxed directly on their proportionate share of
trust net income;
- trust unitholders are entitled to federal income tax depletion
deductions;
- substantially all trust cash must be distributed to trust unitholders;
and
- trust assets are limited to the net profits interests which have a finite
economic life.
RISK FACTORS
Before investing in trust units, you should carefully consider the matters
described under "Risk Factors" beginning on page 16 of this prospectus.
15
<PAGE> 20
RISK FACTORS
RISKS ASSOCIATED WITH THE NATURAL GAS INDUSTRY AND THE UNDERLYING PROPERTIES
NATURAL GAS PRICE DECLINES AND MARKET VOLATILITY COULD RESULT IN LOWER CASH
DISTRIBUTIONS TO TRUST UNITHOLDERS.
The trust's revenues and quarterly cash distributions are highly dependent
upon the prices realized from the sale of natural gas. A material decrease in
the prices realized from the sale of natural gas by Eastern States could reduce
the amount of cash distributions paid to unitholders. Lower natural gas prices
may reduce the amount of natural gas that is economic to produce and reduce net
proceeds available to the trust. The volatility of energy prices reduces the
accuracy of estimates of future cash distributions to trust unitholders. Natural
gas prices can fluctuate widely on a month-to-month basis in response to a
variety of factors that are beyond the control of the trust and Eastern States.
These factors include, among others:
- weather conditions, primarily in the northeast United States;
- the supply and price of domestic and foreign natural gas and oil;
- delivery interruptions by upstream pipeline companies;
- the level of demand;
- worldwide economic and political conditions;
- the price and availability of alternative fuels;
- environmental regulations; and
- worldwide energy conservation measures.
Moreover, government regulations, such as regulation of natural gas
transportation or price controls, if imposed, could affect product prices in the
long term.
Also, any material decrease in the average premium received for Appalachian
Basin production could have an adverse impact on the proceeds received from the
sale of natural gas by Eastern States, resulting in lower cash distributions to
trust unitholders.
Eastern States has agreed to hedge the price paid for the trust's share of
year 2000 natural gas production. As a result of this hedging arrangement, to
the extent that the actual monthly closing NYMEX price for any month during year
2000 exceeds $ per MMbtu, Eastern States will retain all that excess. In
addition, Eastern States will not enter into any hedge agreement for the trust's
share of production from the underlying properties for any production in any
period other than year 2000.
TRUST DISTRIBUTIONS ARE AFFECTED BY COSTS AND CHARGES DEDUCTED BY EASTERN
STATES IN CALCULATING NET PROCEEDS.
Production and development costs, gathering and compression charges and
overhead fees on the underlying properties are deducted in the calculation of
the trust's share of net proceeds. Accordingly, higher or lower production and
development costs, gathering and compression charges or overhead fees will
directly decrease or increase the amount received by the trust for its net
profits interests. Property and production and other taxes are also deducted.
The charges imposed by Eastern States for production costs and both
administrative and drilling overhead fee will adjust each year beginning April
1, 2001 in accordance with an industry standard set forth in the accounting
procedures in the transfer documents or conveyances.
Because of the limited number of interstate pipeline transmission systems
available in the Appalachian Basin as well as the difficult surface topography,
producers such as Eastern States must make significant investments in pipeline
systems to gather natural gas from each well drilled. In addition, Eastern
States must have extensive compression facilities to achieve sufficient line
pressure to produce into interstate transmission pipelines. To sustain its
development drilling program, Eastern States will have to make continuing
investments in these gathering and compression facilities. Eastern States will
deduct from
16
<PAGE> 21
gross proceeds a charge for gathering, compression and processing conducted
using Eastern States' facilities, which charge will include an amount to
reimburse Eastern States for the costs of these services, plus a reimbursement
for depreciation of the facilities and a return on its investment in these
facilities. Large investments in gathering and compression facilities in the
future could decrease the amounts received by the trust for its net profits
interests.
The development costs attributable to the net profits interest in the
underlying leases will be 10% of the development costs incurred by Eastern
States to drill wells in the future. Eastern States currently anticipates
drilling an average of approximately 200 wells per year on the underlying leases
for at least the next five years. The effect of drilling these new wells will be
to reduce the amount of net proceeds received by the trust in the near term,
which will in turn reduce cash available for distribution by the trust to its
unitholders. The amount of net proceeds may fluctuate seasonally as a result of
the weather-related increase of drilling activity in the warmer months of each
year. The purpose of development drilling is to increase production over levels
that would be achieved in the absence of these expenditures.
If the net proceeds from the underlying properties located in a particular
state are less than zero for any quarter, the trust will not receive net
proceeds from those properties until future proceeds from production in that
state exceed the total of the excess costs plus accrued interest during the
deficit period. Development activities may not generate sufficient additional
revenue to repay the costs.
PROVED RESERVE ESTIMATES ATTRIBUTABLE TO THE TRUST ARE UNCERTAIN.
The value of the trust units will depend upon, among other things, the
reserves attributable to the trust's net profits interests. The calculations of
proved reserves included in this prospectus are only estimates. These estimates
were prepared by Ryder Scott. The accuracy of any reserve estimate is a function
of the quality of available data, engineering and geological interpretation and
judgment, and the assumptions used regarding quantities of recoverable natural
gas and natural gas prices. Petroleum engineers consider many factors and make
many assumptions in estimating reserves. Those factors and assumptions include:
- historical production from the area compared with production rates from
other producing areas;
- the availability of pipeline delivery systems;
- the effects of governmental regulation; and
- assumptions about future commodity prices, production and development
costs, and severance and property taxes.
Changes in these assumptions can materially change reserve estimates.
Ultimately, actual production, revenues and expenditures for the underlying
properties will vary from estimates and those variations could be material.
The trust's reserve quantities and revenues are based on estimates of
reserves and revenues for the underlying properties. The method of allocating a
portion of those reserves to the trust is complicated because the trust holds an
interest in net profits and does not own a specific percentage of the natural
gas reserves. See "The Underlying Properties -- Reserves" for a discussion of
the method of allocating proved reserves to the trust.
WEATHER CONDITIONS MAY ADVERSELY AFFECT THE DEMAND FOR AND PRICES PAID FOR
NATURAL GAS.
Generally, natural gas prices in the Appalachian Basin tend to be higher
during the first and fourth quarters of the calendar year because a large
percentage of the usage is for heating purposes. As a result, warmer than normal
winter temperatures, particularly in the northeast United States, can
significantly decrease the demand for natural gas and consequently reduce prices
available in the marketplace. Also, warmer than normal winter temperatures will
generally decrease the amount of the Appalachian Basin premium, as occurred in
the winter of 1998/1999 when the Appalachian Basin premium realized by Eastern
States averaged $0.15 per MMbtu compared to an average of $0.36 per MMbtu for
the seven
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winter periods from 1990/1991 through 1997/1998. The result of these conditions
could decrease the amounts received by the trust for its net profits interests.
INTERRUPTIONS ON THIRD PARTY PIPELINE DELIVERY SYSTEMS COULD REDUCE THE
DELIVERY OF NATURAL GAS PRODUCED FROM THE UNDERLYING PROPERTIES.
Eastern States depends on the availability of third party pipeline delivery
systems to transport over 90% of its natural gas. Any interruptions in the
availability of these systems due to facilities maintenance requirements or
other extraordinary events could inhibit the ability of Eastern States to sell
its natural gas. For example, Columbia Transmission has shut down one of its
pipelines in Kentucky from September 27, 1999 through November 15, 1999 for
replacement of a portion of its pipeline system. This temporary shut-down will
delay the delivery and sale of approximately 30% of Eastern States, natural gas
production in Kentucky, most of which is attributable to the underlying
properties. As a result of this shutdown, the revenues attributable to the
underlying wells for the month of September 1999 and the fourth quarter of 1999
will be reduced, which in turn will reduce the amount of net proceeds payable to
the trust. These interruptions could, therefore, decrease the amount of net
proceeds payable the trust.
RISKS ASSOCIATED WITH THE TRUST UNITS
NET PROCEEDS ARE DERIVED FROM THE SALE OF DEPLETING ASSETS.
The net proceeds payable to the trust are derived from the sale of
depleting assets. The reduction in proved reserve quantities is a common measure
of depletion. Future maintenance and development projects on the underlying
properties will affect the quantity of proved reserves and can offset the
reduction in proved reserves. The timing and size of these projects will depend
on the market prices of natural gas. If Eastern States, as operator of all of
the underlying properties, does not implement additional maintenance and
development projects, the future rate of production decline of proved reserves
may be higher than the rate currently expected by Eastern States.
Because net proceeds are derived from the sale of depleting assets, the
portion of distributions to trust unitholders attributable to depletion may be
considered a return of capital as opposed to a return on investment.
Distributions that are a return on capital will ultimately diminish the
depletion tax benefits available to the trust unitholders, which could reduce
the market price of the trust units over time.
THERE ARE RISKS INHERENT IN DRILLING NEW WELLS ON THE UNDERLYING LEASES.
Eastern States anticipates drilling an average of approximately 200 new
wells per year on the underlying leases for at least the next five years. No
assurance can be given that any new wells will be successful or produce in
commercial quantities or that the number of wells which are projected to be
drilled will actually be drilled. The failure of new wells in Kentucky and West
Virginia to produce in commercial quantities could cause the annual decline in
production from the underlying properties to exceed 3% per year.
PRODUCTION RISKS CAN ADVERSELY AFFECT TRUST DISTRIBUTIONS.
The occurrence of drilling, production or transportation accidents at any
of the underlying properties will reduce trust distributions by the amount of
uninsured costs. These accidents may result in personal injuries, property
damage, damage to productive formations or equipment and environmental damages.
Any of these types of costs would be deducted in calculating net proceeds
payable to the trust.
Eastern States insures against some, but not all, of the hazards associated
with the natural gas industry. For example, it is not insured against the
following hazards:
- fines and penalties;
- pollution events occurring prior to Eastern States' acquisition date of
the properties;
- professional errors and omissions of engineers, geologists and surveyors;
- loss or unrecoverability of oil and natural gas reserves;
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- loss of downhole equipment;
- loss of income due to third party failure to provide equipment or
materials; and
- war and associated events of civil unrest.
As a result, Eastern States may become subject to liabilities or losses that
could be substantial due to uninsured events.
THE TRUST DOES NOT CONTROL OPERATIONS AND DEVELOPMENT OF THE UNDERLYING
PROPERTIES.
Neither the trustee nor the trust unitholders can influence or control the
operation or future development of the underlying properties. Eastern States as
operator of all of the underlying properties is under no obligation to continue
operating the properties. Eastern States can sell any of the underlying
properties or relinquish its ability to control or influence operations. Neither
the trustee nor trust unitholders have the right to replace an operator.
EASTERN STATES MAY TRANSFER OR ABANDON THE UNDERLYING PROPERTIES.
Eastern States may at any time transfer all or part of the underlying
properties to another party. Unitholders will not be entitled to vote on any
transfer, and the trust will not receive any proceeds of the transfer. Following
any material transfer, the underlying properties will continue to be subject to
the net profits interests of the trust, but the net proceeds from the
transferred property would be calculated separately and paid by the transferee.
The transferee would be responsible for all of Eastern States' obligations
relating to the net profits interests on the portion of the underlying
properties transferred, and Eastern States would have no continuing obligation
to the trust for those properties. A transferee of the underlying properties, by
virtue of the transfer, may be obligated to file reports under the Securities
Exchange Act of 1934.
Eastern States or any transferee may abandon any well or property,
including the associated leases, if it reasonably believes that the well or
property is not capable of producing or continuing production in quantities
sufficient to justify further completion, development or operating expenditures,
referred to as commercially economic quantities. Abandonment of a well could
result in termination of the net profits interest relating to the abandoned
well. For a further description of Eastern States' rights to abandon a well, see
"The Underlying Properties -- Sale and Abandonment of Underlying Properties;
Sale of Net Profits Interests."
NET PROFITS INTERESTS CAN BE SOLD OR THE TRUST MAY BE TERMINATED.
The trustee must sell the net profits interests if the holders of 66 2/3%
or more of the trust units approve the sale or vote to terminate the trust. The
trustee must also sell all the net profits interests in both states if the
annual net proceeds from the underlying properties are less than $3.5 million in
Kentucky for any two consecutive years after the year 2000 or less than $3.5
million in West Virginia for any two consecutive years after the year 2000. The
sale of all the net profits interests will terminate the trust. The net proceeds
from the sale of the trust's net profits interests will be distributed to the
trust unitholders.
EASTERN STATES' CONDITIONAL RIGHT OF REPURCHASE MAY FORCE INVESTORS TO SELL
THEIR TRUST UNITS AT AN UNDESIRABLE TIME AND PRICE.
Eastern States will retain the right to repurchase all, but not less than
all, outstanding units at any time at which 15% or less of the outstanding units
are owned by persons or entities other than Eastern States and its affiliates.
These repurchases will be made at no less than the current market price. Because
of this right, investors may be forced to sell their trust units at a time and
price that is undesirable to them.
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EASTERN STATES' DISPOSAL OF TRUST UNITS MAY REDUCE THE MARKET PRICE FOR TRUST
UNITS.
At the completion of the offering, Eastern States will own 2,625,000 trust
units assuming the underwriters' over-allotment option is not exercised. If the
underwriters' over-allotment option is exercised in full, Eastern States will
own 1,443,750 trust units. It may use some or all of the trust units it owns for
a number of corporate purposes, including:
- selling them for cash; and
- exchanging them for interests in oil and natural gas properties or
securities of oil and natural gas companies.
If Eastern States sells these trust units or exchanges trust units in
connection with acquisitions, then additional trust units will be available for
sale in the market, which could result in a reduction in the market price of the
trust units. Except for the limitation on selling trust units within 180 days
following the date of this prospectus as discussed in "Underwriting," Eastern
States is not obligated to maintain a minimum number of trust units. Eastern
States' intentions will vary with market conditions.
EASTERN STATES MAY ENTER INTO CONTRACTS OR RECEIVE PAYMENTS THAT ARE NOT
NEGOTIATED IN ARM'S-LENGTH TRANSACTIONS.
Eastern States and some of its affiliates receive payments for services
relating to the underlying properties. Since the amounts to be paid to Eastern
States for these services were not negotiated at arm's-length, they may exceed
amounts that would be incurred for services from an unrelated third party.
Payments to Eastern States and its affiliates will be deducted in determining
net proceeds payable to the trust. This will reduce the amounts available for
distribution to the trust unitholders. When calculating net proceeds from the
underlying properties, the following will be deducted by Eastern States:
- a fixed production fee for each well, including shut-in wells,
temporarily abandoned wells and other inactive wells, calculated as
follows:
1. a rate per well, except for wells completed below 7,000 feet, of $170
per month for those wells producing five or more Mcfe per day on an
annual basis; or
2. a rate per well, except for wells completed below 7,000 feet, of $70
per month for those wells producing less than five Mcfe per day on an
annual basis; or
3. a rate per well of $300 per month for those wells completed in a zone
below 7,000 feet;
subject in each case to an annual adjustment beginning April 1, 2001 in
accordance with an industry standard set forth in the accounting procedures
in the transfer documents;
- development costs, including a drilling overhead fee of $36,000 for each
well drilled or deepened to another formation, zone or horizon on the
underlying properties on or after September 1, 1999, subject to an annual
adjustment beginning April 1, 2001 in accordance with an industry
standard set forth in the accounting procedures in the transfer
documents;
- Eastern States' charges to gather and compress the natural gas at actual
cost, plus reimbursement for depreciation and to provide a return on
investment of its gathering and compression systems based on a per Mcfe
gathered basis; and
- a fixed overhead fee per well of $65 per month, including shut-in wells,
temporarily abandoned wells and other inactive wells, subject to an
annual adjustment beginning April 1, 2001 in accordance with an industry
standard set forth in the accounting procedures in the transfer
documents, including engineering, accounting and administrative
functions.
In addition, Eastern States typically sells a portion of the production
from the underlying properties to its affiliate, Statoil Energy Services, at
market-based prices. Eastern States intends to continue to do so in the future,
to the extent the terms available from Statoil Energy Services are acceptable.
In 1998, approximately 68% of Eastern States' natural gas production was sold to
Statoil Energy Services. Even if
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Eastern States considers such terms acceptable, however, Eastern States cannot
assure you that such terms will be as good as, or exceed, those available from
unrelated third parties. For a description of our current contract with Statoil
Energy Services, see "The Underlying Properties -- Gas Purchase Contracts."
EASTERN STATES MAY HAVE INTERESTS THAT ARE DIFFERENT FROM YOURS.
Because Eastern States has interests in natural gas properties in the
Appalachian Basin that are not included in the underlying properties, Eastern
States may have interests that are different from yours. For example,
- in setting budgets for development and production expenditures for
Eastern States' properties, including the underlying properties, Eastern
States may make decisions that could adversely affect future production
from the underlying properties. These decisions could include reducing
development expenditures on the underlying properties, which could cause
natural gas production to decline at a faster rate and ultimately result
in lower future trust distributions;
- Eastern States could continue to operate an underlying property and
continue to earn an overhead fee even though abandonment of the property
might result in more net proceeds being available to trust unitholders;
and
- Eastern States could decide to sell or abandon some or all of the
underlying properties, and that decision may not be in the best interests
of the trust unitholders. For example, Eastern States might sell some or
all of the underlying properties to a third party who could reduce
development expenditures on those properties, or Eastern States might
abandon a marginal well that otherwise would continue to produce a net
profit to the trust.
Except for specified matters that require approval of the trust unitholders
described in "Description of the Trust Agreement," the documents governing the
trust do not provide a mechanism for resolving these conflicting interests.
TRUST UNITHOLDERS WILL HAVE LIMITED VOTING RIGHTS AND NO ABILITY TO INFLUENCE
OPERATIONS OF THE UNDERLYING PROPERTIES.
Your voting rights as a trust unitholder are more limited than those of
stockholders of most public corporations. For example, there is no requirement
for annual meetings of trust unitholders or for an annual or other periodic
re-election of the trustee. Additionally, trust unitholders have no voting
rights in Eastern States and therefore will have no ability to influence its
operation and development of the underlying properties.
TRUST UNITHOLDERS WILL HAVE LIMITED ABILITY TO ENFORCE RIGHTS AGAINST EASTERN
STATES.
The trust agreement and related trust law permit the trustee and the trust
to sue Eastern States or any other future owner of the underlying properties to
honor the net profits interests. If the trustee does not take the actions that
you consider appropriate to enforce provisions of the trust agreement and the
trust laws of the State of Delaware, your recourse as a trust unitholder would
likely be limited to bringing a lawsuit against the trustee to compel the
trustee to enforce the provisions of the trust agreement. You probably would not
be able to sue Eastern States or any future owner of the underlying properties.
COURTS IN SOME JURISDICTIONS MAY NOT GIVE EFFECT TO THE SAME LIMITED LIABILITY
OF TRUST UNITHOLDERS THAT IS RECOGNIZED UNDER DELAWARE LAW; THEREFORE, TRUST
UNITHOLDERS COULD HAVE PERSONAL LIABILITY FOR THE TRUST'S LIABILITIES.
Consistent with Delaware law, the trust agreement provides that the trust
unitholders will have the same limitation on liability as is accorded under the
laws of Delaware to stockholders of a corporation for profit. No assurance can
be given, however, that the courts in jurisdictions outside of Delaware will
give effect to this limitation.
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EASTERN STATES' LIABILITY TO THE TRUST IS LIMITED.
The instruments by which the net profits interests are transferred to the
trust provide that Eastern States will not be liable to the trust for performing
its duties in operating the underlying properties as long as it acts in good
faith. As a result, damage to a reservoir from drilling operations, delays in
drilling, completing, reworking or selling production from a well or failure to
enter into a gas sales contract with a particular buyer on favorable terms, and
other similar events, will not subject Eastern States to liability to trust
unitholders so long as its actions were taken in good faith.
THERE ARE RISKS ASSOCIATED WITH THE FINANCIAL CONDITION OF EASTERN STATES AND
ITS AFFILIATES.
Eastern States is engaged primarily in the exploration, development,
production, transportation and marketing of natural gas in the Appalachian
Basin. The ability of Eastern States to operate the underlying properties in a
manner to generate net profits to the trust will be dependent upon its future
financial condition and economic performance, which in turn will depend upon the
supply and demand for natural gas, prevailing economic conditions and other
factors that are beyond the control of Eastern States.
From time to time, Eastern States may enter into hedging contracts for some
of its natural gas production at specified prices for a period of time. Any
gains or losses from hedging activities will not affect amounts paid to the
trust, but large losses under these hedging contracts could have an adverse
impact on the financial condition of Eastern States.
An affiliate of Eastern States, Statoil Energy Services, Inc., currently
purchases approximately 65% of the natural gas produced by Eastern States
pursuant to an existing contract. The ability of Statoil Energy Services to
perform its obligations under the contract will be dependent upon its future
financial condition and economic performance, which in turn will depend upon the
supply and demand for natural gas, prevailing economic conditions and upon
financial, business and other factors beyond the control of Eastern States and
Statoil Energy Services.
AN IRS RULING WILL NOT BE REQUESTED BY EASTERN STATES.
The trust has received an opinion of tax counsel that the trust is a
"grantor trust" for federal income tax purposes. This means that:
- the trust will not be taxed as a corporation;
- you will be taxed directly on your pro rata share of the net income of
the trust, regardless of whether all of that net income is distributed to
you; and
- you will be allowed depletion deductions equal to the greater of
percentage depletion or cost depletion, computed on the tax basis of your
trust units, and your pro rata share of other deductions of the trust.
For a discussion of the material federal income tax consequences of the
ownership and sale of the trust units, see "Federal Income Tax Consequences"
beginning on page 54.
Tax counsel believes that its opinion is in accordance with the present
position of the IRS regarding grantor trusts. Neither Eastern States nor the
property trustee has requested a ruling from the IRS regarding these tax
questions. Neither Eastern States nor the property trustee can assure you that
they would be granted a ruling if requested or that the IRS will continue this
position in the future.
Trust unitholders should be aware of possible state tax implications of
owning trust units. For a brief summary of the material state tax considerations
affecting the trust and trust unitholders, see "State Tax Considerations"
beginning on page 58.
THE TRUST'S NET PROFITS INTERESTS MAY NOT BE RESPECTED IN A BANKRUPTCY
PROCEEDING.
Eastern States believes that the net profits interests should constitute
real property interests under Kentucky law, and a transferable economic interest
under West Virginia law. Approximately 78% of the
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gross acreage that is burdened by the net profits interests is located in West
Virginia. If during the term of the trust Eastern States or any successor owner
of the underlying properties should become a debtor in a bankruptcy proceeding,
it is not entirely clear that the net profits interests would be treated as real
property interests under the laws of Kentucky, or as a transferable economic
interest under West Virginia law. If a determination were made in a bankruptcy
proceeding that a net profits interest did not constitute a real property
interest or a transferable economic interest under applicable state law, it
could be designated an executory contract. An executory contract is a term used,
but not defined, in the federal bankruptcy code to refer to a contract under
which the obligations of both the debtor and the other party are so unsatisfied
that the failure of either to complete performance would constitute a material
breach excusing performance by the other. If a net profits interest were
designated an executory contract and rejected in the bankruptcy proceeding,
Eastern States would not be required to perform its obligations under the net
profits interest and the trust would seek damages as one of Eastern States's
unsecured creditors.
FORWARD-LOOKING STATEMENTS
Some statements made by Eastern States in this prospectus under "Projected
Year 2000 Distributable Cash," statements pertaining to future development
activities and costs and other statements contained in this prospectus are
prospective and constitute forward-looking statements. These forward-looking
statements are based on Eastern States' current projections and estimates and
are identified by words such as "expects," "intends," "plans," "projects,"
"anticipates," "believes," "estimates" and similar words. These forward-looking
statements are not guarantees of future performance and involve known and
unknown risks, uncertainties and other factors that could cause actual results
to differ materially from future results expressed or implied by the
forward-looking statements. The most significant risks, uncertainties and other
factors are discussed under "Risk Factors" above.
Among the factors that could cause actual results to differ materially are:
- natural gas price fluctuations;
- the availability of funds for future development programs;
- the results of the planned development program;
- potential delays or failure to achieve expected production from the
underlying properties;
- potential disruption of operations because of our failure or the failure
of others with whom we have material relationships to achieve timely Year
2000 compliance; and
- potential liability resulting from litigation.
In addition, these forward-looking statements may be affected by general
domestic and international economic and political conditions.
USE OF PROCEEDS
Eastern States will receive all proceeds from the sale of trust units after
deducting underwriting discounts and expenses of the offering paid by Eastern
States. The trust will not receive any proceeds from the sale of the trust
units. The net proceeds before deducting expenses will be approximately $146.5
million, and will increase to approximately $168.4 million if the underwriters
exercise their over-allotment option in full, assuming an initial public
offering price of $20.00 per trust unit. Eastern States intends to use the net
proceeds from the offering to repay a portion of the outstanding indebtedness
owed to Statoil Energy Holdings, Inc. At September 30, 1999, Eastern States'
outstanding indebtedness under the promissory note with Statoil Energy Holdings
was $505.5 million. This promissory note has an 8% annual rate of interest.
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EASTERN STATES
Eastern States, a corporation organized in Delaware, is an independent
energy company engaged in the development, production, acquisition, marketing,
gathering and transportation of natural gas and oil in the Appalachian Basin.
Eastern States is the largest owner of proved natural gas reserves in the
Appalachian Basin. Substantially all of Eastern States' natural gas and oil
reserves are located in Kentucky, Ohio, Virginia and West Virginia.
For the years ended December 31, 1996, 1997 and 1998, Eastern States had
total revenue of $18.2 million, $65.4 million and $104.7 million, and for the
first six months of 1999, Eastern States had total revenue of $57.7 million. For
the years ended December 31, 1996, 1997 and 1998, Eastern States had net income
of $3.9 million, $9.2 million and $8.3 million, and for the first six months of
1999, Eastern States had net income of $6.0 million.
Eastern States currently owns and operates over 5,700 wells in the
Appalachian Basin. At December 31, 1998, Eastern States' estimated net proved
reserves were 1,062 Bcfe, of which 709 Bcfe, or 67%, were proved developed. The
estimated discounted future net cash flows of Eastern States' proved reserves
before United States income taxes were $675 million as of December 31, 1998. For
the six months ended June 30, 1999, total average net sales meter natural gas
and oil production was 104 MMcfe per day, 98% of which was natural gas.
Eastern States is continually evaluating oil and natural gas properties and
other investment opportunities in addition to its development and operations of
existing properties, including the underlying properties.
Eastern States is an indirect wholly owned subsidiary of Statoil Energy.
Statoil Energy also:
- owns and operates power plants throughout the northeast and the
mid-Atlantic region;
- is a leading trader of wholesale electricity and natural gas; and
- specializes in providing a broad range of energy and risk management
services involving the delivery of natural gas, electricity and
alternative fuels to large industrial, institutional and commercial
customers.
- through its indirect wholly owned subsidiary, Eastern States Exploration
Company, owns and operates approximately 600 wells in Pennsylvania, with
estimated net proved reserves of 39 Bcfe at December 31, 1998 and an
average net daily sales meter production of 6 MMcfe for the six months
ended June 30, 1999. Eastern States does not own any interest in Eastern
States Exploration Company.
Statoil Energy is currently an indirect, wholly owned subsidiary of The
Statoil Group. The Statoil Group has substantial ongoing commitments associated
with various development projects worldwide and has numerous international
investment opportunities competing for limited capital. Based upon those capital
commitments, various assets and interests, including Statoil Energy, were
evaluated for strategic ranking, possible sale or joint venture. Based upon that
evaluation, The Statoil Group concluded that it was unable to continue to fund
Statoil Energy's planned increase of the scale of its operations and targeted it
for a possible joint venture.
The Statoil Group retained an investment banking firm, Credit Suisse First
Boston, early in 1999 to implement The Statoil Group's strategy with respect to
Statoil Energy. These activities initially focused on a search for a 50%
strategic partner to obtain and combine complementary assets and activities to
pursue business opportunities in the sector of the U.S. energy market not
regulated by the FERC. Based upon the results of its efforts to pursue this
joint venture strategy, The Statoil Group and its financial advisor concluded
that prospective partners, primarily utility companies, were not interested in
sharing the corporate governance and capital requirements of Statoil Energy. As
a result, on October 13, 1999 The Statoil Group announced that it plans to sell
its equity ownership in Statoil Energy and has initiated discussions with
several companies in that regard.
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None of The Statoil Group, Statoil Energy or Eastern States can provide
assurance that such a sale will be made or when such a sale might be concluded.
While The Statoil Group is currently exploring the possible sale of Statoil
Energy and its subsidiaries, including Eastern States, The Statoil Group may
determine that the sale of individual assets or divisions, including Eastern
States, is more appropriate. If a sale of Statoil Energy or Eastern States is
made, there is no assurance that it would not adversely affect Eastern States or
its ability to operate and develop the underlying properties as contemplated
herein. However, any successor to Eastern States would be subject to the
obligations of Eastern States under the transfer documents and the Trust
Agreement.
After the closing of this offering, Eastern States will continue to own and
operate the underlying properties from which the net profits interests were
conveyed. For additional information regarding Eastern States, see "Information
About Eastern States Oil & Gas, Inc.," beginning on page A-1. PURCHASERS OF
TRUST UNITS WILL NOT ACQUIRE INTERESTS IN OR OBLIGATIONS OF EASTERN STATES,
STATOIL ENERGY OR THE STATOIL GROUP. NONE OF EASTERN STATES, STATOIL ENERGY OR
THE STATOIL GROUP OWES ANY FIDUCIARY DUTY TO THE TRUST UNITHOLDERS.
THE TRUST
The trust was formed in August 1999 under the Delaware Business Trust Act
by the filing of a certificate of trust with the Delaware Secretary of State.
The trust has a property trustee, Bank One, Texas, N.A. and a Delaware trustee,
Bank One Delaware, Inc. The day-to-day operations of the trust will be managed
by a vice president and other officers of the property trustee's Corporate Trust
Administration Department. The Delaware Trustee will have only minimal rights
and duties as necessary to satisfy the requirements of the Delaware Business
Trust Act. At the closing of this offering, the trust agreement will be amended
and restated and will contain the material terms described in "Description of
the Trust Agreement." Effective September 1, 1999, Eastern States will convey
the net profits interests to the trust in exchange for all of the trust units.
The trustee can authorize the trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by the trust. The
property trustee may authorize the trust to borrow from the property trustee as
a lender. Because the property trustee is a fiduciary, the terms of the loan
must be fair to the trust unitholders. The property trustee may also deposit
funds awaiting distribution in an account with itself, if the interest paid to
the trust at least equals amounts paid by the property trustee on similar
deposits.
The trust will pay the trustees a fee of 0.20% of trust cash, before
administrative expenses, per year, which is estimated to be approximately
$45,800 for the year 2000, and a fee of $7,500 for services to terminate the
trust. The trust will also incur legal, accounting and engineering fees,
printing costs and other expenses that will be deducted from the net proceeds
received by the trust before distributions are made to trust unitholders. Total
administrative expenses of the trust are expected to be approximately $300,000
for the year 2000.
PROJECTED YEAR 2000 DISTRIBUTABLE CASH
The net profits interests will be created through two transfer documents to
the trust of Eastern States' interests in the 2,471 underlying wells and all
wells drilled on the underlying leases on or after September 1, 1999. The net
profits interests entitle the trust to receive 80% of the net proceeds received
by Eastern States from the sale of natural gas from the underlying wells and 10%
of the net proceeds received by Eastern States from the sale of natural gas
produced by wells drilled on or after September 1, 1999 on the underlying
leases. Net proceeds equals the gross proceeds received by Eastern States from
the sale of production from the underlying properties less property and
production taxes, production costs, gathering and compression charges,
development costs and administrative and drilling overhead attributable to the
underlying properties. For a more detailed description of net proceeds, see
"Computation of Net Proceeds" on page 51 of this prospectus.
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The amount of trust revenues and cash distributions to trust unitholders
will depend on:
- natural gas prices;
- the volume of natural gas produced and sold;
- the ability of Eastern States to successfully complete wells drilled
after the offering; and
- production, development and other costs.
PROJECTED YEAR 2000 DISTRIBUTABLE CASH
The following table provides a projection of distributable cash related to
the production for the 12 months ending December 31, 2000. This projection
assumes sales volumes and production and development costs estimated by Ryder
Scott. A copy of the Ryder Scott reserve report for the net profits interest is
included as Exhibit B to this prospectus.
Generally, Eastern States sells the natural gas from the underlying
properties under existing contracts that have market-based pricing terms. For
the year 2000, Eastern States has entered into a hedge agreement for the benefit
of the trust. Under this hedge agreement, which is often referred to as a
"collar" arrangement, Eastern States has agreed that if the final monthly
closing NYMEX price for natural gas in any month during year 2000 is less than
$ per MMbtu or more than $ per MMbtu, then Eastern States will calculate
the net proceeds payable to the trust for gas produced during that month based
upon the $ per MMbtu "floor" price or the $ per MMbtu "ceiling" price,
respectively. The calculations in the projections assume a weighted average
NYMEX sales price for year 2000 of $ per MMbtu, which is the mid-point of
the hedge agreement. After the year 2000, the price payable for production
attributable to the net profits interests will be a variable price not subject
to a hedge agreement and may be less than the $ per MMbtu "floor" price, or
more than $ per MMbtu "ceiling" price, specified under the hedge agreement.
The assumed NYMEX price of $2.50 per Mmbtu was then increased by an
Appalachian Basin premium of $0.28 per MMbtu and a Btu adjustment of $0.36 per
MMbtu based on an average Btu content of 1,131 per cubic foot and reduced for
third party gathering and compression charges of $0.16 per Mcf, a 5.4%
compressor fuel and line loss charge by Eastern States of $0.16 per Mcf and
Eastern States' gathering and compression charge of $0.23 per Mcf, resulting in
an average net wellhead price of $2.59 per Mcf of natural gas. Oil prices of
$18.00 per Bbl were also assumed.
Eastern States has prepared this projection as its best estimate of trust
distributable cash for the year 2000, on an accrual or production basis, based
on these pricing assumptions and other assumptions that are described in
"-- Significant Assumptions Used to Prepare the Projected Year 2000
Distributable Cash." Because the projections are prepared on an accrual or
production basis for calendar year 2000, the projections represent an estimate
of cash that would be distributed to unitholders on or about June 25, 2000,
September 25, 2000, December 25, 2000 and March 25, 2001. The projections and
the assumptions on which they are based are subject to significant
uncertainties, many of which are beyond the control of Eastern States or the
trust. ACTUAL 2000 DISTRIBUTABLE CASH, THEREFORE, COULD VARY SIGNIFICANTLY BASED
UPON CHANGES IN ANY OF THESE ASSUMPTIONS.
Distributable cash is particularly sensitive to natural gas prices. See
"-- Sensitivity of Projected Year 2000 Distributable Cash to Natural Gas Prices"
which shows estimated effects on projected year 2000 distributable cash from
changes in natural gas prices. As a result of the effects of the "collar"
arrangement described above during the year 2000, however, distributable cash
for production after the year 2000 will be more sensitive to changes in
prevailing gas prices than is reflected in the referenced disclosure.
As a result of typical production declines for natural gas properties, and,
subject to the success of the drilling of development wells, production
estimates generally decrease from year to year. Due to the seasonal demand for
natural gas, the amount of distributable cash may vary on a seasonal basis.
Furthermore, cash available for distribution may be subject to further seasonal
variation since the weather-related adjustment of drilling activity may result
in higher capital expenditures during the warmer months
26
<PAGE> 31
of each year, when historically lower gas prices are realized. For example, in
the year 2000, Eastern States expects to drill on the underlying properties
approximately 15 wells in the first quarter, approximately 55 wells in the
second quarter, approximately 80 wells in the third quarter and approximately 50
wells in the fourth quarter. ACCORDINGLY, THE PROJECTED YEAR 2000 DISTRIBUTABLE
CASH IS NOT NECESSARILY INDICATIVE OF DISTRIBUTIONS FOR FUTURE YEARS. A PORTION
OF EACH DISTRIBUTION MAY REPRESENT A RETURN OF YOUR ORIGINAL INVESTMENT, RATHER
THAN A RETURN ON YOUR ORIGINAL INVESTMENT. FOR A DESCRIPTION OF THE RISKS
ASSOCIATED WITH THE DEPLETING NATURE OF THE ASSETS OF THE TRUST, SEE "RISK
FACTORS -- NET PROCEEDS ARE DERIVED FROM THE SALE OF DEPLETING ASSETS."
<TABLE>
<CAPTION>
PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTEREST
---------------- ----------------- ----------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Underlying Properties
Volumes Produced:
Natural gas:
Gross production (MMcf)..................... 16,485 5,248 13,713
Less a 1% allowance for
facilities maintenance (MMcf)............ (165) (53) (137)
------- -------- -------
Net production (MMcf)....................... 16,320 5,195 13,576
Oil:
Gross production (MBbls).................... 15.0 -- 12.0
Less a 1% allowance for
facilities maintenance (MBbls)........... (0.2) -- (0.1)
------- -------- -------
Net production (MBbls)...................... 14.8 -- 11.9
Assumed Sales Price of Natural Gas:
NYMEX (MMbtu)................................. $ 2.50
Plus Appalachian Basin and Contract Premium
(MMbtu)..................................... 0.28
-------
Average Sales Meter Price (MMbtu)........... 2.78
Plus Btu Adjustment........................... 0.36
-------
Average Sales Meter Price (Mcf)............. 3.14
Less Third Party Gathering and Compression
Charge (Mcf)................................ (0.16)
-------
Average Net Sales Meter Price (Mcf)........... 2.98
Less Compressor Fuel and Line Loss............ (0.16)
Less Eastern States' Gathering and
Compression Charge (Mcf).................... (0.23)
-------
Average Net Wellhead Price (per Mcf)........ $ 2.59 $ 2.59 $ 2.59
======= ======== =======
Assumed Sales Price of Oil (per Bbl)............. $ 18.00 -- $ 18.00
======= ======== =======
Calculation of Distributable Cash
Revenues:
Natural gas sales............................. $42,236 $ 13,446 $35,134
Oil sales..................................... 267 -- 213
------- -------- -------
Total.................................... 42,503 13,446 35,347
------- -------- -------
</TABLE>
27
<PAGE> 32
<TABLE>
<CAPTION>
PRODUCTION FROM
PRODUCTION FROM NEW WELLS ON COMBINED NET
UNDERLYING WELLS UNDERLYING LEASES PROFITS INTEREST
---------------- ----------------- ----------------
($ IN THOUSANDS)
<S> <C> <C> <C>
Costs:
Production and property taxes................. 3,443 1,089 2,863
Production costs.............................. 4,510 302 3,639
Development costs and drilling overhead....... -- 44,249 4,425
Overhead...................................... 1,875 115 1,511
------- -------- -------
Total.................................... 9,828 45,755 12,438
------- -------- -------
Net proceeds.................................. 32,675 (32,309) 22,909
Net profits percentage........................ 80% 10%
------- -------- -------
Trust cash.................................... 26,140 (3,231) 22,909
Trust administrative expenses................. 300
-------
Trust distributable cash...................... $22,609
=======
Trust distributable cash per trust unit
(10,500,000 trust units).................... $ 2.15
=======
</TABLE>
<TABLE>
<CAPTION>
CASH DISTRIBUTION AS A PERCENTAGE
AMOUNT OF $20.00 TRUST UNIT PRICE
------ ---------------------------------
<S> <C> <C>
Per Trust Unit (10,500,000 trust units):
Total cash distributions (and taxable income before
depletion)........................................... $ 2.15 10.75%
Cost depletion tax deduction............................ (0.91)
------
Taxable income.......................................... 1.24
Income tax rate(a)...................................... 39.6%
------
Income tax to unitholders............................... (0.49)
------
Net cash distributions after tax to unitholders......... $ 1.66 8.30%
====== =====
</TABLE>
- ---------------
(a) Assumes maximum federal effective tax rate applicable to individuals, but
does not take into account state income taxes that may be payable by
unitholders to Kentucky and West Virginia or their state of residence.
SIGNIFICANT ASSUMPTIONS USED TO PREPARE THE PROJECTED YEAR 2000 DISTRIBUTABLE
CASH
Timing of Actual Distributions. In preparing the projected year 2000
distributable cash described above and the sensitivity tables below, the
projected revenues and expenses of the trust were calculated based on the terms
of the transfer documents creating the net profits interests. These calculations
are described under "Computation of Net Proceeds," except that amounts for the
projection and sensitivity tables were calculated on an accrual or production
basis rather than the cash basis prescribed by the transfer documents. As a
result, the proceeds of production for the fourth quarter of the year 2000, and
reflected in the projection and tables, will actually enter into the calculation
of net proceeds to be received by the trust and distributed to unitholders on or
before March 25, 2001, since payments are made to Eastern States for sales of
production 55 to 60 days after the month of sale. Net proceeds from production
for the fourth quarter of 1999 will in fact be received by the trust and
distributed to unitholders in March 2000. The actual amount of the distribution
received by trust unitholders in the first quarter of the year 2000 will be
based on actual production during the quarter commencing October 1, 1999.
Accordingly, the projections represent an estimate of cash that would be
distributed to unitholders on or before June 25, 2000, September 25, 2000,
December 25, 2000 and March 25, 2001 and relate to production for the year 2000.
Production Estimates. Production estimates for the year 2000 are based on
estimates for the underlying properties by Ryder Scott as described in their
reserve report included as Exhibit A to this prospectus. Production from the
underlying properties for the year 2000 is estimated to be 21.8 Bcfe, net to
Eastern States. Eastern States then adjusts such production estimates by
deducting 1% as an allowance
28
<PAGE> 33
for facilities maintenance. For example, from time to time gathering or
transmission pipelines, production equipment or other facilities are shut down
for scheduled or unscheduled maintenance, which can reduce volumes produced from
Eastern States' wells below expected levels. Differing levels of production will
result in different levels of distributions and cash returns.
Natural Gas Prices. Natural gas prices assumed in the year 2000 projected
distributable cash estimate are based on wellhead prices for natural gas. The
wellhead price of $2.59 per Mcf was determined as follows:
NYMEX Price. Eastern States assumed a NYMEX price of $2.50 per MMbtu
in calculating the average wellhead natural gas price, which is the
mid-point of the "collar" arrangement described above. The NYMEX futures
market for the year 2000 as of September 30, 1999 was $2.66 per MMbtu.
Appalachian Basin and Contract Premium. Eastern States increased the
NYMEX price of $2.50 per MMbtu by an assumed Appalachian Basin premium of
$0.28 per MMbtu. For the period 1996 through 1998, natural gas price
indices in the Appalachian Basin have averaged an annual premium of $0.26
per MMbtu more than prices for natural gas contracts traded on the NYMEX
for the delivery of gas at Henry Hub, Louisiana. During these three years,
the average annual Appalachian Basin premium has ranged from $0.14 per
MMbtu to $0.47 per MMbtu. Historically, the premium has been higher in the
first and fourth quarters of the calendar year than in the second and third
quarters. In addition to the assumed Appalachian Basin premium of $0.26 per
MMbtu, Eastern States assumed an additional $0.02 per MMbtu premium
received pursuant to existing contracts that provide for the sale of
approximately 90% of Eastern States' natural gas production. The inclusion
of the Appalachian Basin premium results in an average sales meter price of
$2.78 per MMbtu. The price for natural gas sold under the existing gas
purchase contracts is based on a price published by Inside-FERC. This
published price is on a MMBtu basis. The projected year 2000 distributable
cash is presented on a Mcf basis. In order to adjust natural gas prices
from a MMBtu basis to a Mcf basis, it is necessary to increase the Mcf
price by the Appalachian Basin premium and the Btu adjustment. As discussed
below, the conversion to a Mcf basis is completed after the Btu adjustment.
For a description of the existing gas purchase contracts, including the
determination of the purchase price, see "The Underlying Properties -- Gas
Purchase Contracts."
Btu Adjustment. The average sales meter price of $2.78 per MMbtu is
increased by an assumed Btu adjustment of $0.36. This increase results in
an average sales meter price of $3.14 per Mcf. Eastern States assumes that
production from the underlying properties will have a Btu content for each
cubic foot of natural gas of 1,131 based on actual production data from the
underlying properties for the eight months ended August 31, 1999. This high
Btu content has historically provided an average 13.1% premium over the
standard measure of 1,000 Btu per cubic foot when calculating realized
prices on a per Mcf basis. The Btu adjustment converts the price per MMbtu
into a per Mcf equivalent by increasing the sum of the NYMEX price plus the
Appalachian Basin Premium by 13.1%.
Third Party Gathering and Compression Charge. Eastern States subtracts
an assumed average of $0.16 per Mcf for third party gathering and
compression charges from the average sales meter price to arrive at an
average net sales meter price of $2.98 per Mcf. Eastern States assumed
$0.16 per Mcf based on its estimate of the costs to transport natural gas
production from the underlying properties in the year 2000 through third
party gathering systems. As a result of the completion of various pipeline
projects by Eastern States in 1998 and early 1999, approximately one-third
of Eastern States' natural gas production is subject to third party
gathering and compression charges. Third party gathering and compression
charges are typically approximately $0.50 per Mcf. The assumed $0.16 per
Mcf charge represents a weighted average of all of Eastern States natural
gas production, assuming third parties continue to gather and compress
approximately one-third of Eastern States projected year 2000 natural gas
production.
29
<PAGE> 34
Compressor Fuel and Line Loss. In accordance with the transfer
documents and in connection with gathering and compression services to be
performed by Eastern States, Eastern States will deduct a charge for
volumes consumed for compressor fuel and for volumes lost during gathering
and compression. These lost volumes are referred to as line loss. For
purposes of this presentation, an assumed fuel and line loss of
approximately 5.4% of the average net sales meter price of $2.98 per Mcf
has been deducted. This assumed fuel and line loss charge equates to $0.16
per Mcf. The amount deducted, that is, approximately 5.4% of the average
net sales meter price, is based on Eastern States' historical production
data. The actual amounts to be deducted will be based upon the actual
volumes so consumed or lost by Eastern States in performing these services,
which will vary based upon the actual volumes gathered and compressed by
Eastern States.
Eastern States' Gathering and Compression Charge. In accordance with
the transfer documents, Eastern States will deduct an assumed $0.23 per Mcf
for its gathering and compression charge. This charge represents estimated
gathering and compression costs of $0.09 per Mcf, plus reimbursement for
depreciation and a return on investment of its gathering and compression
systems of $0.14 per Mcf. The $0.09 per Mcf is equal to the actual cost per
Mcf incurred by Eastern States during the eight months ended August 31,
1999 to gather and compress natural gas produced from the underlying
properties. The $0.14 per Mcf is equal to the charge per Mcf that would
have been deducted by Eastern States during the eight months ended August
31, 1999 to reimburse it for depreciation and to provide a return on its
investment in its gathering and compression systems. The projected charge
of $0.23 per Mcf for natural gas gathered and compressed by Eastern States
has been projected in accordance with the projected year 2000 volumes
assumed to be gathered and compressed by Eastern States. For a further
description of these charges, see "Computation of Net Proceeds -- Net
Profits Interests."
In early 1999, Eastern States completed a major pipeline project which
reduced the amount of its natural gas production subject to third party
gathering and compression charges which increased net proceeds. These reduced
third party gathering and compression charges and corresponding increase in net
proceeds will be offset in part by the reimbursement to Eastern States for
depreciation and a return on investment of its gathering and compression systems
described above. However, if location, quality and other differentials return in
the future to more normal levels, there may be more significant differences
between the natural gas price received and the NYMEX price.
The adjustments to wellhead natural gas prices applied in the foregoing
tables are based upon an analysis by Eastern States of the historic price
differentials for production from the underlying properties with consideration
given to the Appalachian Basin premium, Btu content, both third party and
internal gathering and compression charges, and fuel and line loss that may
affect these differentials in the year 2000. There is no assurance that these
assumed differentials will recur in the year 2000 since they are dependent upon
numerous factors outside Eastern States' control. When natural gas prices
decline, the operators of the underlying properties may elect to reduce or
completely suspend production. No adjustments have been made to estimated year
2000 production to reflect potential reductions or suspensions of production.
Oil Prices. Oil sales are realized based on posted prices for Appalachian
Basin production, which has historically been priced at a discount of $2.00 to
$3.00 from the posted price for West Texas Intermediate crude oil.
Production Costs. For calendar year 2000, Eastern States will charge a
fixed overhead fee per well for production costs for wells on the underlying
properties. Except for those wells completed below 7,000 feet, Eastern States
will deduct a monthly fixed production fee of $170 per well for wells producing
five or more Mcf per day and $70 per well for those wells producing less than
five Mcf per day. For wells completed in a zone more than 7,000 feet below the
surface, Eastern States will charge $300 per month. Wells that are shut-in,
temporarily abandoned or otherwise inactive for mechanical reasons or pipeline
constraints or because they may no longer be economic to continue to produce
will be charged the applicable monthly fixed production cost if they are
completed in a zone above 7,000 feet and $300 if they are completed in a
30
<PAGE> 35
zone below 7,000 feet. Each of these fixed costs is subject to adjustment
beginning April 1, 2001 in accordance with an industry standard set forth in the
accounting procedures in the transfer documents. The estimated costs for year
2000 are based upon the Ryder Scott reserve report included as Exhibit A to this
prospectus. The fixed amount of production costs deducted when calculating net
proceeds is reduced by approximately 3%, which amount represents the average
percentage working interest in the underlying properties that Eastern States
does not own. It is assumed that the other working interest owners will bear the
remaining portion of production costs. For a description of production costs,
see "Computation of Net Proceeds -- Net Profits Interests."
Development Costs and Drilling Overhead. In calculating net proceeds,
Eastern States will be reimbursed for all development costs attributable to the
underlying properties, plus a drilling overhead fee of $36,000 for each well
drilled or deepened to another formation, zone or horizon on the underlying
properties on or after September 1, 1999. This drilling overhead fee is subject
to adjustment beginning April 1, 2001 in accordance with an industry standard
set forth in the accounting procedures in the transfer documents. For the year
2000, Eastern States expects to drill approximately 200 wells on the underlying
leases resulting in development costs of approximately $44 million, which
includes a drilling overhead fee of $7.1 million. The drilling overhead fee,
which represents approximately 20% of estimated development cost, covers the
cost of geologists and engineers, as well as reimbursement for lease acquisition
costs, which in some cases are substantial. To take advantage of more favorable
weather conditions, Eastern States expects to seasonally adjust its drilling
activity and to drill more wells during the warmer months of each year, which
may result in higher than average annual capital expenditures during those
periods and lower than average annual capital expenditures during the winter
months. For a further description of these overhead charges, see "Computation of
Net Proceeds -- Net Profits Interests." It is assumed that Eastern States will
own a 98% working interest in all wells drilled on or after September 1, 1999.
Overhead. For the year 2000, Eastern States will charge a $65 per month
fixed overhead fee per producing well on the underlying properties. This fee
will continue to be charged in the event a well is shut-in, temporarily
abandoned or otherwise inactive. This overhead fee will no longer be charged
once a well is plugged and abandoned. Prior to the closing of this offering,
Eastern States has not charged an overhead fee. This fixed cost is subject to an
adjustment beginning April 1, 2001 in accordance with an industry standard set
forth in the accounting procedures in the transfer documents. This overhead fee
is in addition to the production fee described under "-- Production Costs"
above. The fixed amount of overhead deducted when calculating net proceeds is
reduced by approximately 3%, which amount represents the average percentage
working interest in the underlying properties that Eastern States does not own.
It is assumed that the other working interest owners will bear the remaining
portions of overhead.
Administrative Expenses. Trust administrative expenses for the year 2000
are assumed to be $300,000 ($0.03 per trust unit). For a further description of
the trust's administrative expenses, see "The Trust."
Projected After-Tax Cash Distributions as a Percentage of Trust Unit Price
of $20.00. Because the net profits interests are a depleting asset, a portion of
this distribution may be considered a return of your original investment. Except
for tax purposes, the portion that would be considered a return of original
investment is not determinable until the trust unit is sold by a trust
unitholder. For a discussion of alternative ways of measuring the depletion of
oil and natural gas assets, see "Risk Factors -- Net proceeds are derived from
the sale of depleting assets."
The Projected After-Tax Cash Distributions as a Percentage of Trust Unit
Price of $20.00 were computed by:
- taking into account a cost depletion tax deduction of $0.91 per trust
unit;
- determining the amount of federal income tax that would be paid on the
taxable income attributable to a unit at the highest effective tax rate
applicable to individuals for 1999 of 39.6%;
- subtracting the federal income tax to unitholders from the annual cash
distributions; and
- dividing the result by $20.00 per trust unit.
31
<PAGE> 36
Cost depletion is calculated by multiplying the assumed trust unit purchase
price of $20.00 by the cost depletion rate of 4.55%. Cost depletion is
recaptured upon sale of the trust units, which results in the taxation of any
gain on sale as ordinary income, as opposed to capital gain, up to the amount of
cost depletion previously deducted.
When the distributions are less than $0.91 per trust unit, the Projected
After-Tax Cash Distributions as a Percentage of Trust Unit Price of $20.00 would
be the same or greater than the Projected Pre-Tax Cash Distributions as a
Percentage of Trust Unit Price because of cost depletion. In all instances, each
trust unitholder is assumed to have a regular federal income tax liability
sufficient to utilize the depletion deduction. Alternative minimum tax and state
income tax implications have not been considered.
SENSITIVITY OF PROJECTED YEAR 2000 DISTRIBUTABLE CASH TO NATURAL GAS PRICES
Eastern States prepared the following unaudited tables, which demonstrate
the estimated effect that changes in the estimated year 2000 production and in
the price for natural gas could have on the trust's distributable cash. Average
annual NYMEX natural gas prices of less than $ per MMbtu or more than
$ per MMbtu are not included in the tables below because prices for the
trust's portion of year 2000 production is subject to the hedge agreement
provided by Eastern States. For a description of this hedge agreement, see
"-- Projected Year 2000 Distributable Cash" that begins on page 26.
The following tables show:
- the projected distributable cash per trust unit for the year 2000 on the
accrual or production basis;
- the resulting projected distributable cash per trust unit as a percentage
of the purchase price of the trust unit; and
- the resulting projected distributable cash per trust unit as a percentage
of the purchase price of the trust unit, after payment of all federal
income tax, net of available deductions at the highest effective federal
tax rate applicable to individuals of 39.6%.
THE TABLES BELOW ARE NOT A PROJECTION OR FORECAST OF THE ACTUAL OR
ESTIMATED RESULTS FROM AN INVESTMENT IN THE TRUST UNITS. THE PURPOSE OF THE
TABLES IS TO ILLUSTRATE THE SENSITIVITY OF DISTRIBUTABLE CASH AND DISTRIBUTABLE
CASH AS A PERCENTAGE OF TRUST UNIT PURCHASE PRICE TO CHANGES IN THE PRICES OF
NATURAL GAS. THERE IS NO ASSURANCE THAT THE ASSUMPTIONS DESCRIBED ABOVE WILL
ACTUALLY OCCUR OR THAT THE PRICES OF NATURAL GAS WILL NOT CHANGE BY AMOUNTS
DIFFERENT FROM THOSE SHOWN IN THE TABLES.
Due to the seasonal demand for natural gas, the amount of quarterly cash
distributions from the trust is expected to vary during the year. Quarterly
distributions will also vary based on the timing of development expenditures and
the net proceeds, if any, generated by development projects.
SENSITIVITY OF PROJECTED TOTAL YEAR 2000 CASH DISTRIBUTIONS PER TRUST UNIT
<TABLE>
<CAPTION>
% OF YEAR 2000 RESERVE REPORT ESTIMATED PRODUCTION AVERAGE ANNUAL NYMEX NATURAL GAS PRICE PER MMBTU
- -------------------------------------------------- -----------------------------------------------------
$1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25
----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
90%.......................................... $1.04 $1.31 $1.58 $1.84 $2.11 $2.38 $2.65
95%.......................................... 1.15 1.43 1.72 2.00 2.28 2.56 2.85
100%......................................... 1.26 1.56 1.86 2.15 2.45 2.75 3.04
105%......................................... 1.37 1.68 2.00 2.31 2.62 2.93 3.24
110%......................................... 1.48 1.81 2.14 2.46 2.79 3.12 3.44
</TABLE>
32
<PAGE> 37
SENSITIVITY OF PROJECTED YEAR 2000 PRE-TAX CASH DISTRIBUTIONS AS A
PERCENTAGE OF TRUST UNIT PRICE OF $20.00
<TABLE>
<CAPTION>
% OF YEAR 2000 RESERVE REPORT ESTIMATED PRODUCTION AVERAGE ANNUAL NYMEX NATURAL GAS PRICE PER MMBTU
- -------------------------------------------------- -----------------------------------------------------
$1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25
----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
90%.......................................... 5.21% 6.55% 7.88% 9.22% 10.56% 11.89% 13.23%
95%.......................................... 5.76 7.17 8.58 9.99 11.40 12.81 14.23
100%......................................... 6.31 7.80 9.28 10.75 12.25 13.74 15.22
105%......................................... 6.86 8.42 9.98 11.54 13.10 14.66 16.22
110%......................................... 7.41 9.05 10.68 12.31 13.95 15.58 17.21
</TABLE>
SENSITIVITY OF PROJECTED YEAR 2000 AFTER-TAX CASH DISTRIBUTIONS AS A
PERCENTAGE OF TRUST UNIT PRICE OF $20.00
<TABLE>
<CAPTION>
% OF YEAR 2000 RESERVE REPORT ESTIMATED PRODUCTION AVERAGE ANNUAL NYMEX NATURAL GAS PRICE PER MMBTU
- -------------------------------------------------- -----------------------------------------------------
$1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25
----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
90%.......................................... 4.94% 5.75% 6.56% 7.36% 8.17% 8.98% 9.79%
95%.......................................... 5.28 6.13 6.98 7.83 8.68 9.54 10.39
100%......................................... 5.61 6.51 7.40 8.30 9.20 10.09 10.99
105%......................................... 5.94 6.88 7.82 8.77 9.71 10.65 11.59
110%......................................... 6.27 7.26 8.25 9.23 10.22 11.21 12.19
</TABLE>
33
<PAGE> 38
THE UNDERLYING PROPERTIES
GENERAL
The underlying properties are located in the Appalachian Basin states of
Kentucky and West Virginia. The underlying properties consist of Eastern States'
interests in 2,471 existing producing natural gas wells and interests in wells
that Eastern States will drill on or after September 1, 1999 on all of Eastern
States' oil and gas leasehold interests in the states of Kentucky and West
Virginia, except for the excluded interests discussed below. The trust will not
have a net profits interest in any properties or interests acquired by Eastern
States on or after September 1, 1999. The working interests of Eastern States
comprising the underlying properties are held under leases and farmout
agreements with third parties. Substantially all of the working interests are
subject to landowners' royalties and may be subject to additional royalties or
other obligations burdening the working interests. These royalties do not bear
lease operating expenses, but reduce the revenue interests attributable to the
underlying properties.
Eastern States has, on average, greater than a 97% working interest and a
net revenue interest of approximately 87% in the underlying properties. Eastern
States currently operates all of the wells on the underlying properties. Ryder
Scott estimates that 331 Bcfe of proved developed and 437 Bcfe of proved
undeveloped natural gas reserves are attributable to the underlying properties,
which estimates are the subject of their reserve report as of August 31, 1999
included as Exhibit A to this prospectus. Ryder Scott estimates that 211 Bcfe of
proved developed reserves and 29 Bcfe of proved undeveloped reserves are
attributable to the net profits interest free of future costs and expenses,
which estimates are the subject of their reserve report included as Exhibit B to
this prospectus.
Eastern States currently owns approximately 4,700 producing wells in
Kentucky and West Virginia. When selecting producing wells to be included in the
2,471 underlying wells, Eastern States excluded wells with any of the following
characteristics:
- approximately 1,350 wells owned by a financial institution that are
Section 29 production payment properties, most of which are operated by
Eastern States;
- approximately 220 wells drilled during the 20 months ended August 31,
1999, each of which has a limited production history and a high decline
profile;
- approximately 10 wells with high operating costs;
- approximately 300 marginal producing wells and associated leases, i.e.,
producing less than 2 Mcf per day, which will most likely have to be
abandoned in the next five to 10 years;
- approximately 50 wells with title or consent issues; and
- approximately 300 wells in which Eastern States is not the operator.
Eastern States' transfer to the trust of a net profits interest in 2,471
underlying wells in Kentucky and West Virginia is intended to create a diversity
of well profiles and a diversity of value. The well with the highest discounted
net present value represents less than 0.5% of the value of all underlying
wells. The inclusion of a large number of future drilling opportunities on the
underlying leases along with the underlying wells will provide statistical and
geological diversity in more than one potential producing zone in Kentucky and
West Virginia. Approximately 73% of the 2,471 underlying wells are located in
West Virginia and approximately 27% are located in Kentucky. All of the
underlying wells, except for one, are producing and profitable. One well is
temporarily shut-in and is expected to resume production in November and be
profitable at that time.
Eastern States excluded leases and other interests in Kentucky and West
Virginia from the underlying leases with any of the following characteristics:
- leases and mineral interests in Kentucky pertaining to the Rome
exploration area, which is characterized by high exploration risk;
- the portion of underlying leases that have been farmed out to third
parties; and
- leases or interests with known transfer or title issues, including all
potential coalbed methane exploration and developmental rights.
34
<PAGE> 39
Eastern States has an inventory of approximately 1.2 million gross acres,
excluding the Rome exploration area but before giving effect to the other
excluded interests, comprising the underlying leases and has established a
drilling schedule for new sites in Kentucky and West Virginia. Eastern States
anticipates drilling an average of 200 wells per year on the underlying leases
for at least the next five years. Without future development, the underlying
properties would typically experience an average 5.5% annual decline in
production. Planned development expenditures included in the Ryder Scott reserve
report, which, total $285 million through 2007 or $28.5 million net to the
trust, are expected to reduce the natural rate of decline in production to an
average of 3% per year. While the number of wells to be drilled on an annual
basis following the offering is subject to a number of factors beyond the
control of Eastern States, the underlying leases are expected to yield a number
of drillsites which would sustain development of the properties at current
levels for the foreseeable future.
If Eastern States, on or after September 1, 1999, successfully drills,
deepens or recompletes any of the 2,471 underlying wells or any well within
1,000 feet of any of the 2,471 underlying wells at or above the base of the
Devonian Shale, the trust will have an 80% net profits interests in the net
proceeds from the sale of natural gas from these wells. The base of the Devonian
Shale ranges in Kentucky and West Virginia from 2,500 feet to 7,500 feet below
the surface. If Eastern States, on or after September 1, 1999, commences a well
on the underlying leases, except for wells located within 1,000 feet of an
existing well and completed above the base of the Devonian Shale, or drills,
deepens or recompletes any of the 2,471 underlying wells on the underlying
leases below the base of the Devonian Shale, the trust will have a 10% net
profits interest in the net proceeds from the sale of natural gas from these
wells. Currently, Eastern States has no proved reserves below the base of the
Devonian Shale within the underlying leases.
Although Eastern States has not obtained title opinions with respect to the
drillsites, Eastern States is not aware of any title deficiencies that would
preclude it from drilling any of the locations. Eastern States has drilled over
400 wells in Kentucky and West Virginia since 1994 with a completion rate of
approximately 98%, and expects the completion rate on wells drilled on or after
September 1, 1999 to be similar. Moreover, the drillsites are expected to have
the same general production characteristics as the producing wells included in
the underlying properties. No assurance can be given, however, that any wells
drilled on or after September 1, 1999 will be successful or produce in
commercial quantities. For a further discussion of Eastern States' title to the
drillsites referred to above, see "-- Title to Properties."
Production from the wells to which the underlying properties relate is
typically subject to, in one degree or another:
- landowner royalties and other burdens and obligations retained under oil
and gas leases;
- relocation provisions under oil and gas leases with coal mining entities;
- overriding royalty interests; and
- other working interests in the wells.
Royalty and overriding royalty interests entitle the holders thereof to a
percentage of the oil and natural gas produced from the wells or the proceeds
therefrom and are generally delivered free of all expenses of production but may
be subject to post-production costs such as:
- production or gathering taxes;
- costs to treat the natural gas to render it marketable; and
- transportation or gathering and compression costs.
Royalty interests are usually reserved by the lessor under an oil and gas
lease. Overriding royalty interests are carved out of a lessee's share of
production under an oil and gas lease and are generally reserved by a
predecessor in title or reserved under farmout agreements. Certain leases are
not burdened by any royalty interests and only a minor portion of the underlying
leases are burdened by overriding royalties.
35
<PAGE> 40
THE APPALACHIAN BASIN
The Appalachian Basin is the oldest and geographically one of the largest
oil and natural gas producing regions in the United States. From 1859 to 1993,
more than 700,000 wells have been drilled in the Appalachian Basin and have
produced an estimated three billion barrels of oil and 42 trillion cubic feet of
natural gas. Although the Appalachian Basin has known sedimentary formations
indicating the potential for oil and natural gas reservoirs to depths of 13,000
feet or more, oil and natural gas is currently produced principally from shallow
blanket formations at depths of 1,000 to 7,000 feet. These formations are
characterized by slow recovery of the reserves in place, low rates of production
and wells that generally produce for longer than 20 years and often more than 50
years. Although commercial success varies widely from well to well, operators in
the Appalachian Basin historically have experienced drilling completion rates
exceeding 90% in these shallow formations.
For the period 1991 through 1998, wellhead natural gas prices in the
Appalachian Basin have averaged on an annual basis $0.25 per MMbtu more than
prices for natural gas contracts traded on the NYMEX for the delivery of natural
gas at Henry Hub, Louisiana. During these eight years, the Appalachian Basin
annual premium has ranged from $0.14 per MMbtu to $0.47 per MMbtu. This premium
has averaged $0.26 MMbtu for the last three years. The higher average prices are
principally due to the proximity to a substantial number of industrial and
commercial end users in the northeast United States. The Appalachian Basin
premium is offset, at least in part, by the high gathering and compression costs
in the Appalachian Basin.
The combination of its long-lived production, low drilling costs, high
drilling completion rates at shallow depths and proximity to natural gas markets
has had a substantial impact on the development of the Appalachian Basin
resulting in a highly fragmented operating environment. In 1998, Kentucky and
West Virginia had more than 500 independent operators and more than 85,000
producing oil and natural gas wells. Also, the historical availability of tax
shelter capital has resulted in extensive drilling in the shallow formations
with these low technical risk characteristics.
DISTRICTS COMPRISING THE UNDERLYING PROPERTIES
The districts comprising the underlying properties are as follows:
Pikeville Area, Kentucky
The Pikeville Area includes approximately 34% of the total net proved
reserves in the underlying properties. The underlying properties in this
district are concentrated in Pike, Knott, Martin, Floyd and Breathitt counties,
Kentucky on approximately 262,000 gross acres, which excludes the Rome
exploration area. Natural gas is produced predominantly from the Maxton, Big
Lime, Berea and Devonian Shale formations at depths ranging from 1,000 to 5,500
feet. Sales meter production attributable to the underlying properties averaged
13 MMcfe per day during the first eight months of 1999. Significant development
potential still remains in this district, with 505 proved undeveloped locations
identified for exploitation as of August 31, 1999.
Brenton Area, West Virginia
The Brenton Area includes approximately 38% of the total net proved
reserves in the underlying properties. The underlying properties in this
district are located mainly in Logan, Mingo, McDowell and Wyoming counties in
southern West Virginia on approximately 397,000 gross acres. Natural gas is
produced predominantly from the Maxton, Big Lime, Berea and Devonian Shale
formations at depths ranging from 2,000 to 7,000 feet. Sales meter production
attributable to the underlying properties averaged 14 MMcfe per day for the
first eight months of 1999. Significant development potential still remains in
this district, with 674 proved undeveloped locations identified for exploitation
as of August 31, 1999.
36
<PAGE> 41
Madison Area, Eastern West Virginia
The Madison Area includes approximately 20% of total net proved reserves in
the underlying properties. The underlying properties in this district are
located in Lincoln, Kanawha, Boone, Raleigh, Fayette, Nicholas and Clay counties
in south central West Virginia on approximately 374,000 gross acres. Natural gas
is produced predominantly from the Maxton, Big Lime, Big Injun, Weir, Berea and
Devonian Shale formations at depths ranging from 1,700 to 6,000 feet. Sales
meter production attributable to the underlying properties averaged 11 MMcfe per
day for the first eight months of 1999. Significant development potential still
remains in this district, with 296 proved undeveloped locations identified for
exploitation as of August 31, 1999.
Weston Area, West Virginia
The Weston Area includes approximately 8% of the total net proved reserves
in the underlying properties. The underlying properties in this district are
located largely in Jackson, Gilmer, Doddridge, Roane, Calhoun, Harrison and
Wetzel counties in northern West Virginia on approximately 192,000 gross acres.
Natural gas is produced from Upper Devonian sandstone formations at depths
ranging from 1,800 to 5,000 feet. Sales meter production attributable to the
underlying properties averaged 8 MMcfe per day for the first eight months of
1999. Some development potential remains in this district, with 53 proved
undeveloped locations identified for exploitation as of August 31, 1999.
HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES
The following table provides oil and natural gas wellhead volumes, average
realized sales prices, revenues and direct operating expenses relating to the
underlying properties for 1996, 1997 and 1998 and for the eight-month periods
ended August 31, 1998 and 1999. The related pro forma adjustments for the year
ended December 31, 1998 and the eight months ended August 31, 1999 are also
shown. Eastern States did not own all of the underlying properties for each of
the periods indicated. The audited statements of revenues and direct operating
expenses of the underlying properties for the years ended December 31, 1996,
1997 and 1998 and unaudited statements for the eight-month periods ending August
31, 1998 and 1999 begin on page F-3 in this prospectus. The pro forma
adjustments reflect changes to historical results as if the offering had
occurred on December 31, 1997 and give effect to the adjustments described on
page F-13 in this prospectus.
<TABLE>
<CAPTION>
EIGHT MONTHS
YEAR ENDED DECEMBER 31, ENDED AUGUST 31,
--------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
Wellhead volumes:
Natural gas (MMcf)........................... 19,318 19,960 19,040 13,184 11,967
Oil (MBbls).................................. 35.1 30.6 20.4 12.9 18.9
Average realized sales prices:
Natural gas (per Mcf)........................ $ 2.84 $ 2.62 $ 2.20 $ 2.27 $ 2.14
Oil (per Bbl)................................ $ 19.29 $ 17.35 $ 11.86 $ 12.17 $ 12.17
Revenues:
Natural gas sales............................ $54,877 $52,303 $41,835 $29,879 $25,594
Oil sales.................................... 677 531 242 157 230
------- ------- ------- ------- -------
Total................................ 55,554 52,834 42,077 30,036 25,824
------- ------- ------- ------- -------
Direct operating expenses:
Production and property taxes................ 5,179 4,872 3,809 2,713 2,338
Production expenses.......................... 6,300 5,106 3,603 2,401 2,401
------- ------- ------- ------- -------
Total................................ 11,479 9,978 7,412 5,114 4,739
------- ------- ------- ------- -------
Excess of revenues over direct operating
expenses.................................. $44,075 $42,856 $34,665 $24,922 $21,085
======= ======= ======= ======= =======
</TABLE>
37
<PAGE> 42
<TABLE>
<CAPTION>
EIGHT MONTHS
YEAR ENDED ENDED AUGUST 31,
DECEMBER 31, 1998 1999
----------------- -------------------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C>
Excess of revenues over direct operating costs.............. $34,665 $21,085
Pro Forma Adjustments:
Revenue................................................... (2,439) (1,533)
Production expenses....................................... (897) (599)
Overhead.................................................. (1,870) (1,250)
------- -------
Total pro forma adjustments....................... (5,206) (3,382)
Net proceeds.............................................. 29,459 17,703
Net profits percentage.................................... 80% 80%
------- -------
Trust cash................................................ 23,567 14,162
Trust administrative expenses............................. (300) (200)
------- -------
Trust distributable cash.................................. $23,267 $13,962
======= =======
Trust distributable cash per unit (10,500,000 units issued
and outstanding)....................................... $ 2.22 $ 1.33
======= =======
</TABLE>
DISCUSSION AND ANALYSIS OF HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES
The excess of revenues over direct operating expenses from the underlying
properties was $44,075,000 for 1996, $42,856,000 for 1997 and $34,665,000 for
1998. The excess of revenues over direct operating expenses was $24,922,000 for
the eight months ended August 31, 1998 and $21,085,000 for the eight months
ended August 31, 1999. The changes in excess of revenues over direct operating
expenses were primarily related to changes in volumes and prices. Natural gas
sales accounted for greater than 99% of total revenues for the three-year period
ended December 31, 1998 and the eight-month period ended August 31, 1999.
Natural Gas Volumes. Natural gas sales volumes from the underlying
properties increased 3.3% from 1996 to 1997, decreased 4.6% from 1997 to 1998
and decreased 9.2% from the eight-month period ending August 31, 1998 to the
eight-month period ending August 31, 1999. The increase was primarily
attributable to development projects in 1996 and 1997 and the decrease in 1998
was primarily attributable to the fact that none of the development wells
drilled in 1998 and 1999 are included in the underlying properties. Also, the
wells drilled in 1997 experienced a higher production decline in the eight
months ended August 31, 1998 as compared to the eight months ended August 31,
1999.
Natural Gas Prices. The average realized natural gas sales price decreased
7.7% from $2.84 per Mcf in 1996 to $2.62 per Mcf in 1997, decreased 16% from
$2.62 per Mcf in 1997 to $2.20 per Mcf in 1998 and decreased 5.7% from $2.27 per
Mcf in the eight-month period ending August 31, 1998 to $2.14 per Mcf in the
eight-month period ending August 31, 1999. Gas prices for the underlying
properties have generally tracked Appalachian Basin market prices. Gas prices
realized in 1996 for Appalachian Basin natural gas were high due to a prolonged
cold weather period in January and February 1996. The amount of natural gas in
storage in the northeastern United States was at extremely low levels and prices
remained strong throughout the year. As a result of this cold weather, the
Appalachian Basin premium averaged $0.47 per MMbtu for 1996. NYMEX gas prices
remained strong in 1996 and 1997, while the Appalachian Basin premium was weak
in 1997 due to unusually warm winter weather in the Northeast. As a result,
prices realized for 1997 were 7.7% lower. In 1998, both the NYMEX price and the
Appalachian Basin premium weakened due in part to the second consecutive warm
winter in the Northeast. This caused 1998 realized prices to drop 16% as
compared to 1997. Prices continued to drop in the first and second quarter of
1999. Natural gas prices in July 1999 and for the rest of the year have
strengthened for both NYMEX and the Appalachian Basin premium in anticipation of
a normal winter in the Northeastern United States. See the table below for
market prices.
38
<PAGE> 43
Set forth below is a table that reflects average NYMEX closing prices and
average Appalachian Basin prices for 1996, 1997, 1998 and the eight months ended
August 31, 1999, and the average annualized Appalachian Basin premiums for such
periods based upon such average annualized prices. The average Appalachian Basin
prices shown below represent the average natural gas prices published by Inside
FERC -- Appalachian Basin for CNG Transmission Corp. and Columbia Gas
Transmission Corp.
<TABLE>
<CAPTION>
AVERAGE
AVERAGE AVERAGE ANNUALIZED AVERAGED
NYMEX APPALACHIAN APPALACHIAN ANNUALIZED
CLOSING BASIN BASIN APPALACHIAN
PRICES PRICES PREMIUM BASIN
($/MMBTU) ($/MMBTU) ($/MMBTU) PREMIUM
--------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
1996..................................... $2.59 $3.06 $0.47 18.1%
1997..................................... 2.59 2.76 0.17 6.6
1998..................................... 2.11 2.25 0.14 6.6
Eight months ended August 31, 1999....... 2.07 2.22 0.15 7.2
</TABLE>
Natural gas prices have continued to increase since the spring of 1999 and the
average Appalachian Basin natural gas price for September 1999 was $3.05 per
MMbtu, which consists of an Appalachian Basin premium of $0.14 per MMbtu.
The average realized sales price of natural gas production from the
underlying properties during 1998 was $2.20 per Mcfe, which is approximately
$0.09 above the average of the monthly closing NYMEX natural gas futures
contract prices in 1998. The average realized sales price of natural gas
production from the underlying properties during 1998 on a pro forma basis as if
the offering had closed on December 31, 1997 was $2.05 per Mcfe, which is
approximately $0.06 below the average of the monthly closing NYMEX natural gas
futures contract prices in 1998. This difference in the NYMEX futures prices is
due to the lower than average Appalachian Basin premium in 1998, which resulted
primarily from significantly warmer than normal average prevailing winter
temperatures in 1998, as well as high gathering and compression charges.
Direct operating expenses. Direct operating expenses decreased 13.1% from
$11,479,000 in 1996 to $9,978,000 in 1997, followed by a 25.7% decrease to
$7,412,000 in 1998. The production costs for 1996 and for the six months ended
June 30, 1997 show operating costs of the predecessor owner, Blazer Energy.
Since the acquisition, Eastern States has reduced these costs. For the
eight-month period ending August 31, 1998 compared to the eight-month period
ending August 31, 1999, direct operating expenses decreased 7.3% from $5,114,000
to $4,739,000 due to continued efficiencies as a result of the assimilation of
the Blazer properties.
Development costs. Virtually all of the underlying properties were either
purchased or drilled by Eastern States in the four-year period from 1994 to
1997. Development costs rose 86.7% from $12,024,000 in 1996 to $22,445,000 in
1997 as major development projects were completed. Eastern States expects
development costs on the underlying leases to be approximately $44 million per
year for at least the next five years. None of the wells drilled in 1998 and
1999 are included in the underlying properties because of their higher decline
profile compared to the current decline profile of wells drilled in the
four-year period from 1994 to 1997. Development costs incurred by Blazer Energy
prior to its acquisition by Eastern States on June 30, 1997 have not been
included in the historical results table above.
The following table shows the development costs relating to natural gas
wells drilled by Eastern States in Kentucky and West Virginia for 1996, 1997 and
1998 and for the eight months ended August 31, 1999. The table also shows
projected development costs for the four months ended December 31, 1999 and the
projected development costs included in projected year 2000 distributable cash.
The development costs for 1996 and 1997 include those for wells drilled by
Eastern States on the underlying properties, but do not include those for wells
drilled by Blazer Energy on the underlying properties for the period prior to
Eastern States' acquisition of Blazer Energy on June 30, 1997, which are not
available to Eastern States.
39
<PAGE> 44
The development costs for 1998 and the eight months ended August 31, 1999
are for wells drilled by Eastern States in Kentucky and West Virginia. Eastern
States has excluded those wells from the 2,471 underlying wells to be
transferred to the trust due to their limited production history and relatively
high decline profile.
The projected development costs for the four months ended December 31, 1999
and for the year ended December 31, 2000 are based on average costs to develop
undeveloped properties. Volumes for these time periods are derived from the
Ryder Scott reserve report for the underlying properties.
<TABLE>
<CAPTION>
TOTAL FINDING AND
DEVELOPMENT DEVELOPMENT DEVELOPMENT
NATURAL COSTS COSTS NET COSTS
GAS WELLS EXCLUDING DRILLING INCLUDING RESERVE INCLUDING
----------- OVERHEAD OVERHEAD OVERHEAD ADDITIONS OVERHEAD
GROSS NET ($ IN MILLIONS) ($ IN MILLIONS)(A) ($ IN MILLIONS) (BCFE) ($/MCFE)
----- --- --------------- ------------------ --------------- --------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1996..... 54 53 $ 9.4 $2.6 $12.0 15.2 $0.79
Year Ended December 31, 1997..... 88 88 17.5 5.0 22.4 27.9 0.80
Year Ended December 31, 1998..... 165 162 36.2 5.8 42.0 53.4 0.79
Eight months ended August 31,
1999........................... 114 111 21.3 4.0 25.3 42.6 0.59
Four months ended December 31,
1999 (projected)............... 67 66 12.4 2.4 14.8 26.0 0.57
--- --- ----- ---- ----- ----
Total 1999....................... 181 177 33.7 6.4 40.1 68.6 0.58
--- --- ----- ---- ----- ----
Year ended December 31, 2000
(projected).................... 200 197 37.1 7.1 44.2 68.6 0.64
</TABLE>
- ---------------
(a) Drilling overhead for 1996 and 1997 is based on Eastern States actual
overhead allocated to its drilling operations. For 1998, the eight month and
four month periods of 1999 and year 2000, the amounts are based on the
drilling overhead fee of $36,000 to be deducted in calculating net proceeds
payable to the trust for each well drilled on the underlying properties.
RESERVES
Ryder Scott estimated oil and natural gas reserves attributable to the
underlying properties and the net profits interests as of August 31, 1999, which
are the subject of their reserve reports included as Exhibit A and Exhibit B to
this prospectus. Numerous uncertainties are inherent in estimating reserve
volumes and values, and the estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing of
production of the reserves may vary significantly from the original estimates.
Ryder Scott calculated reserve quantities and revenues for the net profits
interests from projections of reserves and revenues attributable to the combined
interests of the trust and Eastern States in the underlying properties. Because
the trust owns net profits interests and not a specific ownership percentage of
the oil and natural gas reserve quantities, proved reserves for the trust's net
profits interests attributable to the 2,471 underlying wells are calculated by
subtracting from 80% of proved reserves, reserve quantities of a sufficient
value to pay 80% of the future estimated production and development costs,
before overhead and trust administrative expenses that are deducted in
calculating net proceeds. Proved reserves for the net profits interests
attributable to the proved undeveloped reserves owned by Eastern States in
Kentucky and West Virginia are calculated by subtracting from 10% of the proved
undeveloped reserves, reserve quantities of a sufficient value to pay 10% of the
future estimated production and development costs, before overhead and trust
administrative expenses that are deducted in calculating net proceeds.
Accordingly, proved reserves for the net profits interests reflect quantities
that are calculated after reductions for future production and development costs
and expenses based on the price and cost assumptions used in the reserve
estimates. The total proved reserves deducted for the future costs and expenses
in determining the net profits interests were approximately 67 Bcfe.
The standardized measure of discounted future net cash flows presented
below was prepared using assumptions required by the Financial Accounting
Standards Board. These assumptions include the use of
40
<PAGE> 45
August 31, 1999 prices for natural gas and costs for estimated future
development and production expenditures to produce the proved reserves.
Because natural gas prices are influenced by seasonal demand, use of August
31, 1999 prices may not be the most accurate basis for estimating future
revenues or reserve data. Future net cash flows are discounted at an annual rate
of 10% as required by the Financial Accounting Standards Board. There is no
provision for federal income taxes because future net revenues are not subject
to taxation at the trust level. The weighted average August 31, 1999 wellhead
natural gas price used to determine the standardized measure was $2.75 per Mcf
for the underlying properties and $2.61 per Mcf for the net profits interests.
The $0.14 per Mcfe difference represents reimbursement for depreciation and a
return on Eastern States' investment in its gathering and compression systems.
During 1999, Eastern States filed estimates of operated oil and natural gas
reserves as of December 31, 1998 with the U.S. Department of Energy on Form
EIA-23. These estimates are consistent with the reserves reported in this
prospectus for the underlying properties as of December 31, 1998, with the
exception that Form EIA-23 includes only reserves from properties that had been
acquired and were operated by Eastern States at that date. Neither Eastern
States nor the trust has reported reserves for the net profits interests with
any Federal authority or agency prior to the filing of this prospectus.
Proved Reserves
The following table shows proved developed reserves, proved undeveloped
reserves, total proved reserves, future net revenues and the standardized
measure discounted future net cash flows at August 31, 1999 for the underlying
properties, the underlying wells, the underlying leases, a subtotal and the net
profits interests. The Ryder Scott reserve reports are included as Exhibits A
and B to this prospectus. The quantities reflected under the column subtotal in
the table below represent 80% of reserves attributable to the underlying wells
and 10% of reserves attributable to the underlying leases before deducting
reserve quantities sufficient to pay $0.05 per Mcfe for office expenditures,
information systems and other capitalized costs which are included in production
costs and $0.14 per Mcfe for reimbursement for depreciation and to provide a
return on investment of Eastern States' gathering and compression systems. For a
further description of the computation of net proceeds, see "Computation of Net
Proceeds -- Net Profits Interests."
<TABLE>
<CAPTION>
UNDERLYING UNDERLYING UNDERLYING NET PROFITS
PROPERTIES(100%) WELLS(80%) LEASES(10%) SUBTOTAL INTERESTS
----------------- ---------- ----------- -------- -----------
($ IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Proved developed reserves
Natural gas (MMcf)................ 329,581 263,665 -- 263,665 210,018
Oil (MBbls)....................... 260 208 -- 208 171
Natural gas equivalents (MMcfe)... 331,139 264,911 -- 264,911 211,044
Proved undeveloped reserves
Natural gas (MMcf)................ 436,533 -- 43,653 43,653 29,083
Oil (MBbls)....................... -- -- -- -- --
Natural gas equivalents (MMcfe)... 436,533 -- 43,653 43,653 29,083
Total proved reserves
Natural gas (MMcf)................ 766,114 263,665 43,653 307,318 239,101
Oil (MBbls)....................... 260 208 -- 208 171
Natural gas equivalents (MMcfe)... 767,672 264,911 43,653 308,564 240,127
Future net revenues................. $1,470,948 $577,182 $74,947 $652,129 $577,207
Standardized measure of discounted
future net cash flows............. $ 367,277 $211,889 $10,242 $222,131 $200,420
</TABLE>
The following table summarizes the changes in proved reserves of the
underlying properties for the periods indicated. The data is presented assuming
the underlying properties were acquired before
41
<PAGE> 46
December 31, 1995. Reserve estimates for underlying properties that Eastern
States acquired in 1996 and 1997 are not available prior to the date acquired.
For purposes of calculating quantities of proved reserves as of December 31,
1995 and 1996, proved reserves were derived by assuming they equal the reserves
at December 31, 1997, plus production, less positive revisions from drilling by
Eastern States for the years 1996 and 1997. This table does not include any
revisions, extensions or discoveries prior to Eastern States' acquisition of
Blazer Energy on June 30, 1997.
<TABLE>
<CAPTION>
100% UNDERLYING PROPERTIES
--------------------------------------
NATURAL GAS
NATURAL GAS OIL EQUIVALENTS
(MMCF) (MBBLS) (MMCFE)
----------- ---------- -----------
<S> <C> <C> <C>
Balance, December 31, 1995............................... 666,996 338 669,024
Revisions, extensions, discoveries and additions...... 6,094 -- 6,094
Production............................................ (19,318) (35) (19,528)
------- --- -------
Balance, December 31, 1996............................... 653,772 303 655,590
Revisions, extensions, discoveries and additions...... 11,167 -- 11,167
Production............................................ (19,960) (31) (20,146)
------- --- -------
Balance, December 31, 1997............................... 644,979 272 646,611
Revisions, extensions, discoveries and additions...... 63,187 20 63,307
Production............................................ (19,040) (20) (19,160)
------- --- -------
Balance, December 31, 1998............................... 689,126 272 690,758
Revisions, extensions, discoveries and additions...... 88,955 7 88,995
Production............................................ (11,967) (19) (12,081)
------- --- -------
Balance, August 31, 1999................................. 766,114 260 767,672
======= === =======
Proved Developed Reserves
Balance, December 31, 1995............................... 360,942 338 362,970
Balance, December 31, 1996............................... 347,718 303 349,536
Balance, December 31, 1997............................... 338,925 272 340,557
Balance, December 31, 1998............................... 344,907 272 346,539
Balance, August 31, 1999................................. 329,581 260 331,139
</TABLE>
There are 1,528 proved undeveloped drilling locations in the underlying
leases identified for exploration. Eastern States expects to spend approximately
$44 million per year on development costs for at least the next five years. Of
these development costs, 10% will be attributable to the net profits interests
of the trust.
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
The following table provides the summary calculation of the standardized
measure of discounted future net cash flows of the underlying properties, the
underlying wells, the underlying leases, a subtotal and the net profits
interests as of August 31, 1999. Because the underlying properties and the trust
are not taxable at the underlying property level or trust level, no provision is
included for income taxes.
<TABLE>
<CAPTION>
UNDERLYING UNDERLYING UNDERLYING NET PROFITS
PROPERTIES (100%) WELLS (80%) LEASES (10%) SUBTOTAL INTERESTS
----------------- ----------- ------------ --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Future cash flows............. $ 2,129,626 $ 729,285 $121,802 $ 851,087 $ 628,249
Future costs:
Production.................. 373,705 151,881 18,385 170,266 51,042
Development................. 284,973 222 28,470 28,692
----------- --------- -------- --------- ---------
Future net cash flows....... 1,470,948 577,182 74,947 652,129 577,207
10% discount factor......... (1,103,671) (365,293) (64,705) (429,998) (376,787)
----------- --------- -------- --------- ---------
Standardized measure........ $ 367,277 $ 211,889 $ 10,242 $ 222,131 $ 200,420
=========== ========= ======== ========= =========
</TABLE>
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<PAGE> 47
NATURAL GAS SALES PRICES AND PRODUCTION COSTS
The following table sets forth the annual production, the average realized
sales price per Mcf produced and the average production cost per Mcfe for each
of the years ended December 31, 1996, 1997 and 1998 and for the eight-month
period ended August 31, 1999 for the underlying properties on a historical basis
and for the year ended December 31, 1998 and the eight months ended on August
31, 1999 for the net profits interests on a pro forma basis. Pro forma figures
are calculated by attributing 80% of production for the underlying properties to
the net profits interests and assuming gas gathering and compression costs,
production costs, development costs and overhead provided for in the conveyances
were in effect for the periods indicated. Average realized sales price reflected
in the table below generally represents the wellhead price of natural gas which
is net of gathering and compression charges and excludes hedging activity.
Production costs as used in the following table include, for all properties,
production and property taxes and production expenses. Overhead has not been
included as a production cost. Average production costs were calculated on an
Mcfe basis in order to spread the cost over combined oil equivalent production
and natural gas production.
For the net profits interests, development and production costs have been
directly deducted from future cash flows. The remaining production costs are
solely production and property taxes.
<TABLE>
<CAPTION>
PRO FORMA FOR NET PROFITS
HISTORICAL FOR UNDERLYING PROPERTIES INTERESTS
------------------------------------------ ---------------------------
EIGHT MONTHS EIGHT MONTHS
YEAR ENDED DECEMBER 31, ENDED YEAR ENDED ENDED
--------------------------- AUGUST 31, DECEMBER 31, AUGUST 31,
1996 1997 1998 1999 1998 1999
------- ------- ------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Wellhead volumes (MMcf).... 19,318 19,960 19,040 11,967 19,040 11,967
Average realized sales
price per Mcf produced... $ 2.84 $ 2.62 $ 2.20 $ 2.14 $ 2.05 $ 1.99
Average production cost per
Mcfe..................... $ 0.59 $ 0.50 $ 0.39 $ 0.39 $ 0.43 $ 0.44
</TABLE>
PRODUCING ACREAGE AND WELL COUNTS
For the following data, "gross" refers to the total wells or acres in which
Eastern States owns a working interest and "net" refers to gross wells
multiplied by the percentage working interest owned by Eastern States. The
number of gross acres shown below does not exclude the acreage attributable to
the excluded wells or excluded leases and other interests.
Underlying Properties
<TABLE>
<CAPTION>
WELLS
--------------
GROSS NET GROSS ACRES NET ACRES
----- ----- ----------- ---------
<S> <C> <C> <C> <C>
Brenton District....................................... 560 533 397,000 360,000
Madison District....................................... 583 581 374,000 337,000
Weston District........................................ 661 623 192,000 172,000
Pikeville District..................................... 667 666 262,000 230,000
----- ----- --------- ---------
Total........................................ 2,471 2,403 1,225,000 1,099,000
===== ===== ========= =========
</TABLE>
In addition, the number of gross acres reflected in this table excludes
approximately 90,000 acres representing the Rome exploration area, but does not
exclude (1) leases that have been farmed out to third parties and (2) leases or
interests with known transfer or title issues, including all potential coalbed
methane exploration and development rights.
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<PAGE> 48
The following is a summary of the number of natural gas wells drilled and
completed by Eastern States on the leases which comprise the underlying
properties during the last three years. There are no wells listed under the year
ended December 31, 1998 and the eight months ended August 31, 1999 because all
wells drilled by Eastern States during this time period are excluded from the
underlying wells because of their limited production history and relatively high
decline profile. This summary does not include wells drilled by Blazer Energy
prior to its acquisition by Eastern States on June 30, 1997. Unless otherwise
indicated, all wells drilled are developmental.
<TABLE>
<CAPTION>
EIGHT MONTHS
YEAR ENDED DECEMBER 31, ENDED
--------------------------------------- AUGUST 31,
1996 1997 1998 1999
----------- ----------- ----------- ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Natural Gas Wells....................... 54 53 88 88 -- -- -- --
== === == === == === == ===
</TABLE>
Excluded Properties
Natural gas wells drilled on or after January 1, 1998 are not included in
the underlying wells. The following is a summary of the number of these wells:
<TABLE>
<CAPTION>
YEAR ENDED EIGHT MONTHS
DECEMBER 31, ENDED AUGUST 31,
1998 1999
-------------- ----------------
GROSS NET GROSS NET
----- --- ------ ----
<S> <C> <C> <C> <C>
Natural Gas Wells......................................... 165 162 114 111
=== === === ===
</TABLE>
Reserve estimates for the 273 net wells drilled on or after January 1, 1998
are 96 Bcfe with development costs, before drilling overhead, of $57.5 million.
This results in finding and development costs before drilling overhead of $0.60
per Mcfe. If drilling overhead were included for wells drilled on or after
January 1, 1998, the finding and development costs would have been $0.70 per
Mcfe. The projected finding and development costs, including drilling overhead,
for the year 2000 is $0.64 per Mcfe.
OPERATIONS
All of the wells and properties to which the underlying properties relate
are currently operated by Eastern States, although Eastern States is under no
obligation to continue to serve as the operator for the properties. As operator,
Eastern States is responsible for conducting and directing all operations with
respect to the properties, as permitted and required by, and within the limits
of, any applicable operating agreements, including:
- producing the wells;
- discharging obligations of the joint account;
- holding funds for non-operators;
- maintaining records and filing and furnishing governmental reports;
- conducting drilling, testing, completing, reworking, and plugging
operations; and
- maintaining insurance for the joint account.
With respect to the underlying properties, Eastern States must act as a
reasonably prudent operator would act in the Appalachian Basin under the same or
similar circumstances if it were acting with respect to its own properties.
The trust will be entitled to bring actions against Eastern States to
enforce its rights under the transfer documents. If the trustee fails to bring
an action on behalf of the trust, each unitholder has a statutory right under
the Delaware Business Trust Act to bring a derivative action in the Delaware
Court of Chancery on behalf of the trust to enforce the rights of the trust
under the transfer documents,
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<PAGE> 49
including rights relating to the standard of conduct owed to the trust by
Eastern States with respect to operations relating to the underlying properties.
Due to the criteria utilized in selecting wells to be subject to and
burdened by the net profits interests, the lands upon which the wells subject to
the net profits interests are located will, in many instances, also contain
other wells which did not satisfy the selection criteria and which therefore
will not become subject to the net profits interests. In these instances,
Eastern States will generally serve as the operator for all of the wells located
on lands subject to a particular lease. As the operator of this leased property,
Eastern States will generally have a contractual duty to any other working
interest owners to act as a reasonably prudent operator with respect to the
operations of the leased property.
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES; SALE OF NET PROFITS INTERESTS
Eastern States and any transferees will have the right to abandon any well
or property included in the underlying properties if, in its opinion, the well
or property ceases to produce or is not capable of producing in commercially
paying quantities. Eastern States will typically consider a well not capable of
producing in commercially paying quantities if the well's future monthly
operating expenses are projected to exceed the well's future monthly income.
Eastern States' criteria for determining whether to abandon a well or property
are not mandated by contract but are subject to the reasonably prudent operator
standard described above. Under the applicable state law, Eastern States will be
responsible for plugging and abandoning the wells on the underlying properties
for which it is the operator. The costs incurred to plug and abandon wells that
are subject to the net profits interests will be deducted in calculating net
proceeds payable to the trust. Upon abandonment, that portion of the net profits
interests will be extinguished. Eastern States may also sell a well or property
free of the net profits interest in lieu of the payment of abandonment costs or
delay rentals, provided that the trust receives its attributable percentage of
the net proceeds of any sale. Eastern States does not expect to plug or abandon
any of the underlying wells in the next three years.
Eastern States has the right to sell all or any portion of the underlying
properties without the consent of the trust or the unitholders; however, the
purchaser of any of the underlying properties will acquire the underlying
properties subject to the net profits interests relating thereto, except under
the circumstances described below where the trust may be required to release the
net profits interests, subject to its receipt of the fair value thereof. Upon
the transfer of all or a portion of the underlying properties, Eastern States
may retain the right to operate the underlying properties subject to the net
profits interest and the terms of the transfer documents. Following a transfer,
the underlying properties will continue to be subject to the net profits
interests, and the net proceeds attributable to the transferred property will be
calculated separately and paid by the transferee. The transfer documents will be
recorded in the appropriate real property records to give notice of the net
profits interests to Eastern States' creditors and transferees. In accordance
with the transfer documents any purchaser will be subject to the standard of a
reasonably prudent operator in the Appalachian Basin with respect to
development, operation and abandonment of the underlying properties. A
transferee of the underlying properties, by virtue of the transfer, may be
obligated to file reports under the Securities Exchange Act of 1934.
Upon notice from Eastern States, the trust is required to sell, for cash,
net profits interests related to underlying properties which Eastern States is
selling to an unaffiliated party. These types of sales may not exceed $3 million
in any calendar year or $20 million on an aggregate basis for the life of the
trust. Under these circumstances, the trust will receive:
- 80% of the net proceeds from the sale of any of the 2,471 underlying
wells; and
- 10% of the net proceeds from the sale of any of the underlying leases or
the sale of any well drilled on the underlying leases on or after
September 1, 1999.
In addition, as an owner of the underlying properties, Eastern States may
enter into farmout, operating, participation and other similar agreements
covering the property. The net profits interest held by the trust would then be
calculated on the interest retained by Eastern States under the agreement and
not on Eastern States' or the trust's original interest before modification by
the agreement. Eastern States may
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<PAGE> 50
enter into any of these agreements without the consent or approval of the
trustee or any trust unitholder. However, Eastern States' interest in entering
into any of these types of agreements should be parallel with that of trust
unitholders because Eastern States is retaining 20% of the net profits interest
in the 2,471 underlying wells and 90% of the net profits interest in all wells
drilled on the underlying leases on or after September 1, 1999. Immediately
after this offering, Eastern States will also own up to 25% of the outstanding
trust units.
GAS PURCHASE CONTRACTS
Eastern States will market the natural gas produced from the underlying
properties. Although it is not contractually obligated to do so, Eastern States
will attempt to obtain the best prices available to it in the marketplace.
Generally, natural gas produced from the underlying properties will be sold by
Eastern States under existing contracts that have market-based terms. Eastern
States currently has significant contracts with affiliates of CNG Transmission
Corp and its own affiliate, Statoil Energy Services, Inc. Each of these
contracts expire in October 2000. The trustee has the right under the trust
agreement to review the charges under the gas purchase contracts.
In 1998, approximately 90% of the natural gas produced by Eastern States
was sold under these contracts. For the eight-month period ended August 31,
1999, approximately 68% of Eastern States' natural gas production was sold to
Statoil Energy Services and approximately 22% was sold to affiliates of CNG
Transmission Corp.
Under the CNG contracts, affiliates of CNG purchase natural gas from
Eastern States based on the terms contained in confirmations which the parties
enter into from time to time. The CNG confirmations contain the following:
- quantity;
- price;
- delivery point; and
- effective period of the confirmation.
The price under the CNG contracts is based on the published price of Inside
FERC-Appalachian Basin for CNG on an MMbtu basis, plus a $0.02 per MMbtu
premium, less applicable gathering, compression and processing fees. The price
for the natural gas is inclusive of all taxes levied on production or
transportation of the natural gas up to the delivery point. Payment from CNG
affiliates is due by the 55th day following delivery.
Each CNG confirmation sets forth the quantity of natural gas to be
delivered by Eastern States to the delivery point. The delivery point is, in
general, the point of the interconnection of Eastern States' gathering
facilities with the metering facilities of CNG's interstate transmission or
gathering pipeline system. Eastern States is responsible for delivery of natural
gas to the delivery point. Title and risk of loss to the natural gas pass to the
CNG affiliate at the delivery point. Each CNG confirmation sets forth the period
of time that the terms of the confirmation are effective. The effective period
of a confirmation with the CNG affiliates has typically been for 12 months.
The contract with Statoil Energy Services is also based on the terms
contained in confirmations which the parties enter into from time to time. These
confirmations contain the same information as the CNG confirmations discussed
above.
The price under the Statoil Energy Services contract is based on the
published price of Inside FERC -- Appalachian Basin for Columbia Gas
Transmission Corp., for natural gas delivered into Columbia Gas Transmission's
interstate transmission pipeline system, on an MMbtu basis, plus a $0.02 per
MMbtu premium, less gathering, compression and processing fees. Eastern States
is responsible for all taxes attributable to the natural gas before the delivery
point. Statoil Energy Services is responsible for all taxes attributable to the
natural gas after the delivery point. Title and risk of loss pass to Statoil
Energy Services at the delivery point. Payment is due from Statoil Energy
Services by the 55th day following delivery.
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<PAGE> 51
Eastern States has historically sold its natural gas on the spot market,
i.e., contracts of one year or less. However, Eastern States may enter into
longer term contracts in the future.
HEDGING ACTIVITIES
Eastern States has historically entered into hedging contracts with respect
to its natural gas production at specified prices for a specified period of
time. As described under the caption "Projected Year 2000 Distributable Cash"
that begins on page 25, Eastern States has agreed to hedge the trust's share of
year 2000 production from the underlying properties under a so-called "collar"
arrangement. Eastern States has eliminated its exposure to this "collar"
arrangement by entering into a comparable agreement with a third party. After
the closing of this offering, Eastern States may continue to enter into hedging
contracts with respect to natural gas production from the underlying properties
only for the portion of natural gas that is attributable to its retained
interests. For example, Eastern States may enter into hedging contracts for up
to 20% of the production from the 2,471 underlying wells and up to 90% of the
production from wells drilled on the underlying leases after the closing of this
offering. Except for Eastern States obligations under the "collar" arrangement,
any gains or losses from Eastern States' other hedging activities will not
affect amounts paid to the trust. Long-term contracts for the physical sale and
delivery in the future of natural gas volumes are not hedging contracts.
REGULATION
Natural Gas Regulation. The availability, terms and cost of transportation
significantly affect sales of natural gas. The interstate transportation and
sale for resale of natural gas is subject to federal regulation, including
transportation rates, storage tariffs and various other matters, primarily by
the Federal Energy Regulatory Commission. Federal and state regulations govern
the price and terms for access to natural gas pipeline transportation. The
Federal Energy Regulatory Commission's regulations for interstate natural gas
transmission in some circumstances may also affect the intrastate transportation
of natural gas.
While natural gas prices are currently unregulated, Congress historically
has been active in the area of natural gas regulation. Eastern States cannot
predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have on the
operations of the underlying properties.
Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The Federal Energy Regulatory
Commission implemented regulations on January 1, 1995, to establish an indexing
system for transportation rates for oil that could increase the cost of
transporting oil to the purchaser.
Eastern States' gathering operations are subject to occupational safety,
health and operational regulations relating to the design, installation,
testing, construction, operation, replacement and management of facilities.
Pipeline safety issues have recently been the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. Eastern States believes that its operations, to the extent they may be
subject to current natural gas pipeline safety or other health and safety
requirements, comply in all material respects with these requirements.
Eastern States is not able to predict what effect, if any, these
regulations might have.
Environmental Regulation. Companies that are engaged in the oil and gas
industry are affected by federal, state and local laws regulating the discharge
of materials into the environment or otherwise relating to environmental
protection. Eastern States believes that it is in substantial compliance with
the environmental laws and regulations that apply to the operations of the
underlying properties. Eastern States has not previously incurred material
expenses in complying with environmental laws and regulations that affect its
operations of the underlying properties and does not currently expect that
future compliance will have a material adverse effect on the trust or the
quarterly distributions. For a detailed description of the environmental
regulations applicable to Eastern States, see Appendix A "Information About
Eastern States Oil & Gas, Inc. -- Business and Properties -- Environmental
Matters."
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<PAGE> 52
State Regulation. The states of Kentucky and West Virginia may regulate the
production, gathering and sale of oil and natural gas, including imposing
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. These states may also regulate rates of production, may
establish maximum daily production allowables from both oil and gas wells based
on market demand or resource conservation, or both, and may require that certain
wells be shut-in.
The states of Kentucky and West Virginia also regulate the service which is
provided to customers by Eastern States in connection with the direct supply of
natural gas to homeowners.
The petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws. Some of those laws relate to
occupational safety, resource conservation and equal employment opportunity.
Eastern States does not believe that compliance with these laws will have a
material adverse effect upon the trust unitholders.
TITLE TO PROPERTIES
Eastern States believes that its title to the underlying properties is, and
the trust's title to the net profits interest will be, good and defensible
according to the standards generally accepted in the Appalachian Basin oil and
gas industry. "Good and defensible title" means record ownership of oil and
natural gas leasehold rights which afford the owner with the right to explore
for, drill and produce oil and natural gas from the property.
The underlying properties are typically subject, in one degree or another,
to one or more of the following:
- royalties, overriding royalties and other burdens under oil and gas
leases;
- relocation provisions under oil and gas leases with coal mining entities;
- contractual obligations, including, in some cases, development
obligations, arising under operating agreements, farmout agreements,
production sales contracts and other agreements that may affect the
properties or their titles;
- liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors
and contractual liens under operating agreements;
- pooling, unitization and communitization agreements, declarations and
orders; and
- easements, restrictions, rights-of-way and other matters that commonly
affect property.
To the extent that these burdens and obligations affect Eastern States'
rights to production and the value of production from the underlying properties,
they have been taken into account in calculating the trust's interests and in
estimating the size and the value of the reserves attributable to the net
profits interests. Eastern States believes that the burdens and obligations
affecting the underlying properties and the net profits interests are
conventional in the industry for similar properties. Eastern States also
believes that the burdens and obligations do not in the aggregate materially
interfere with the use of the underlying properties and will not materially
adversely affect the value of the net profits interests.
Although the matter is not entirely free from doubt, Eastern States
believes that the net profits interests should constitute real property
interests under Kentucky law, but not under West Virginia law. Under West
Virginia law, however, it is likely, although not entirely certain, that a net
profits interest constitutes an economic interest in gross production measured
by net profits, and that title to the economic interests can be transferred by a
transfer document. Nevertheless, Eastern States will record the conveyances in
the appropriate real property records of Kentucky and West Virginia. If during
the term of the trust, Eastern States should become a debtor in a bankruptcy
proceeding, it is not entirely certain that the net profits interests would be
treated as real property interests under the laws of Kentucky, and they would
not be so treated under West Virginia law. If a determination were made in a
bankruptcy proceeding that a net profits interest did not constitute a real
property interest or a transferable economic interest under applicable state
law, it could be designated an executory contract. An executory contract is a
term used, but not defined, in the federal bankruptcy code to refer to a
contract under which the
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<PAGE> 53
obligations of both the debtor and the other party are so unsatisfied that the
failure of either to complete performance would constitute a material breach
excusing performance by the other. If a net profits interest were designated an
executory contract and rejected in the bankruptcy proceeding, Eastern States
would not be required to perform its obligations under the net profits interest
and the trust would seek damages as one of Eastern States' unsecured creditors.
Although no assurance can be given, Eastern States believes that the net profits
interests should not be subject to rejection in a bankruptcy proceeding as
executory contracts.
YEAR 2000
"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant by January 1, 2000 may cause material adverse
effects to companies and organizations that rely upon those systems. The trust's
timely receipt of royalty income and disbursement of distributable income to
trust unitholders will largely depend upon performance of computer systems of
Eastern States, the trust's transfer agent and other third parties. These third
parties include oil and natural gas purchasers and significant service providers
such as electric utility companies and natural gas plant, pipeline and gathering
system operators.
Eastern States has reviewed its computer systems and is making the
necessary modifications for Year 2000 compliance. Eastern States is completing
modifications and testing of its land computer programs and expects to complete
remediation and testing by the end of November 1999. The remaining computer
systems have been assessed and are believed to be compliant.
Some of Eastern States' critical field equipment, such as natural gas
compressors, are partially controlled or regulated by embedded computer chips.
Based on a preliminary review of all operating areas, Eastern States has
identified no significant compliance exceptions. Based on its review,
remediation efforts and the results of testing, Eastern States does not believe
that timely modification of its computer systems for Year 2000 compliance
represents a material risk to the trust. Eastern States estimates that total
costs related to Year 2000 compliance efforts will be approximately $200,000 of
which approximately $130,000 has been incurred and expensed through September
30, 1999. The trust will not incur any of Eastern States' Year 2000 costs.
Eastern States has identified significant third parties whose Year 2000
compliance could affect Eastern States and has formally inquired about their
Year 2000 status. Eastern States has received responses to all of its inquiries.
All respondents have indicated that they will be Year 2000 compliant by January
1, 2000. In addition, the property trustee and its primary service provider for
trust distributions and account maintenance have indicated that they will be
Year 2000 compliant by January 1, 2000. Despite its efforts to assure that the
third parties are Year 2000 compliant, Eastern States cannot provide assurance
that all significant third parties will achieve compliance in a timely manner. A
third party's failure to achieve Year 2000 compliance could have a material
adverse effect on Eastern States' operations and cash flow, and therefore have a
material adverse impact on timely trust distributions to trust unitholders. For
example a third party might fail to deliver revenue related to the trust's net
profits interest to Eastern States, or Eastern States might fail to deliver the
income of the net profits interest to the trust. In these situations, the
trustee would be unable to make distributions of those amounts to trust
unitholders on a timely basis.
Eastern States has prepared contingency plans in the event of any potential
problems resulting from failure of Eastern States' or significant third party
computer systems and compressors on January 1, 2000. As part of its contingency
plans, Eastern States will have certain key employees working on both December
31, 1999 and January 1, 2000 to determine that Eastern States' computer systems
and compressors continue to operate normally. Eastern States anticipates minimal
problems will be encountered which would affect trust assets, but the most
reasonably likely worst scenario is the loss of production from 10% to 20% of
the underlying wells for several days in January 2000 due to compressors not
properly functioning. Such loss is estimated to be less than 1% of projected
year 2000 revenue.
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<PAGE> 54
LITIGATION
Various legal actions that have arisen in the ordinary course of business
are pending with respect to Eastern States and its affiliates. None of these
proceedings would reasonably be expected to have a material adverse impact on
Eastern States' results of operations or financial position.
Any liability relating to the underlying properties prior to September 1,
1999 will be borne by Eastern States. Any liabilities relating to the underlying
properties on or after September 1, 1999 could proportionately reduce the amount
of net proceeds payable to the trust based on the percentage of the trust's net
profits interests.
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<PAGE> 55
COMPUTATION OF NET PROCEEDS
The provisions governing the computation of the net proceeds are detailed
and extensive. The following describes all of the material terms of the net
profits interests but the computation of net proceeds is subject to and
qualified by the more detailed provisions of the transfer documents of the net
profits interests that are filed as exhibits to the registration statement. You
should review those exhibits before making an investment in the trust units. See
"Available Information" which describes how you may obtain copies of those
exhibits.
NET PROFITS INTERESTS
The net profits interests are defined net profits interests carved from the
underlying properties. The net profits interests entitle the trust to receive
80% of the net proceeds from the sale of natural gas produced from the 2,471
underlying wells and 10% of the net proceeds from the sale of natural gas
produced from wells drilled by Eastern States on the underlying leases on or
after September 1, 1999.
The underlying properties are adjacent, in some cases, to other properties
in which Eastern States has an interest and which generally produce from the
same formations and horizons as the wells included in the underlying properties.
The trust will not receive a net profits interest in the net proceeds from the
sale of natural gas from these excluded properties.
The amounts paid to the trust for the net profits interests are based on
the definition of "net proceeds" contained in the transfer documents and
described below. Under the transfer documents, net proceeds are computed
quarterly on a state-by-state basis. Eastern States pays the net proceeds
attributable to a computation period to the trust on or before the 20th day of
the third calendar month following the end of each calendar quarter. Eastern
States will not pay to the trust interest on the net proceeds held by Eastern
States prior to payment to the trust. The property trustee makes quarterly
distributions to trust unitholders. For a description of the terms of the trust
agreement pertaining to cash distributions, see "Description of the Trust
Units -- Distributions and Income Computations."
Net proceeds payable to the trust equal the excess of aggregate gross
proceeds over aggregate costs. For the trust's share of year 2000 production
from the underlying properties, Eastern States has agreed to a hedge for the
benefit of the trust. Under such hedge agreement, Eastern States has agreed that
if the monthly closing NYMEX price for year 2000 natural gas production during
any month is less than the "floor" price of $ per MMbtu or more than the
"ceiling" price of $ per MMbtu, the net proceeds payable to the trust for
such production will be calculated as if the monthly closing NYMEX price for
such month was $ per MMbtu or $ per MMbtu, respectively. The net
proceeds of the trust attributable to the trust's share of production for any
period other than year 2000 will not be calculated upon any hedge, collar or
other derivative agreement entered into by Eastern States.
Aggregate gross proceeds means 80% of the gross proceeds attributable to
the underlying wells plus 10% of the gross proceeds attributable to wells
drilled on the underlying leases on or after September 1, 1999. Aggregate costs
means 80% of the costs attributable to the underlying wells plus 10% of the
costs attributable to the wells drilled on the underlying leases on or after
September 1, 1999, plus excess costs as of the end of the prior computation
period, plus interest on the amount of excess costs as of the end of the prior
computation period calculated at the prime rate for the current computation
period.
Gross proceeds means the amounts received by Eastern States from sales of
natural gas and oil produced from the underlying properties. The following are
excluded from the calculation of gross proceeds:
- all general property (ad valorem), production, severance, sales,
gathering, excise and other taxes (other than income taxes) and gathering
and compression costs if they are deducted or excluded from the proceeds
of sales of production;
- any amount attributable to nonconsent operations conducted on the
underlying properties as to which Eastern States is a nonconsenting party
and which is dedicated to the recoupment or reimbursement of costs and
expenses of the consenting party by the terms of the relevant
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<PAGE> 56
agreement providing for the nonconsent operations has exercised its right
under the applicable operating or other agreements not to consent to
payment of expenses for activities conducted by other working interest
owners;
- any amount for natural gas lost in the production or marketing thereof or
used for drilling, production or plant operations conducted for the
purpose of drilling for, producing, processing or marketing natural gas
from the underlying properties;
- any payment made to the owner of an underlying property for:
-- payments for the sale or transfer of the underlying properties (subject
to the net profits interest);
-- payments for the sale of equipment or other personal property,
fixtures, gathering systems and other tangible property located on the
underlying properties or used in connection therewith;
-- natural gas not taken, but to the extent payments are allocated to
natural gas taken in the future, payments are included, without
interest, in gross proceeds when the natural gas is taken;
-- damages, other than drainage or reservoir injury;
-- rental for reservoir use; and
-- payments in connection with the drilling of any well.
Gross proceeds includes payments for future production if they are not
subject to repayment in the event of insufficient subsequent production. Gross
proceeds also includes cash payments received by the owner of the underlying
properties in respect of any lease or farmout of the underlying properties.
Costs mean, on a cash basis, generally the sum of:
- all payments to mineral or land owners, such as royalties or other
burdens against production, delay rentals, shut-in natural gas payments,
minimum royalty or other payments for drilling or deferring drilling;
- any taxes other than income taxes to the extent not previously deducted
in calculating gross proceeds, including estimated and accrued ad valorem
and other property and production taxes;
- all development costs, which include all costs, expenses and liabilities
of exploring, drilling and reworking natural gas wells, including
allocated expenses such as labor, vehicle and travel costs and materials;
- seismic, geophysical and other exploration costs;
- third party costs and charges associated with gathering, compressing and
processing natural gas;
- Eastern States' costs and charges associated with gathering, compressing
and processing natural gas, plus reimbursement for depreciation and a
return on investment;
- plugging and abandonment costs;
- overhead charges, which include a producing well fixed fee, a fixed per
well general and administrative fee and a fixed per well fee for wells
drilled or deepened;
- costs of insurance, if any, pertaining to the ownership or operation of
the underlying properties;
- costs of any litigation pertaining to the underlying properties arising
from activities conducted after September 1, 1999, including settlements,
damages, refunds, fines, interest and penalties paid to third parties or
governmental authorities, provided that the owner of the underlying
properties has acted as a reasonably prudent operator;
- amounts previously included in gross proceeds but subsequently paid as a
refund, interest or penalty;
- costs and expenses for renewals or extensions of leases; and
- at the option of the owner of an underlying property, accruals for costs
approved under authorizations for expenditure and prepayment of costs
reasonably expected to be incurred within 180 days of the quarter in
which the prepayment is made.
Effective September 1, 1999, Eastern States will deduct costs when
calculating the net proceeds that it has not previously charged or, in some
cases, deduct higher costs than what it had previously charged. These costs were
not charged in the past because Eastern States owns approximately a 97% working
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interest in the properties subject to the net profits interest and would,
therefore, bear substantially all of the costs. When calculating net proceeds,
Eastern States will proportionately reduce these costs based on the trust's
percentage net profits interests. These costs are set forth in the transfer
documents and include the following:
Production Costs. As payment for operating the wells included in the
underlying properties, except for wells producing below 7,000 feet, Eastern
States will deduct a monthly fixed production fee of $170 per well for those
wells producing five or more Mcf per day on an annual basis and $70 per well for
those wells producing less than five Mcf per day on an annual basis. For those
wells completed at depths below 7,000 feet, Eastern States will deduct a monthly
fixed production fee of $300 per well. Wells that are shut-in, temporarily
abandoned or otherwise inactive for mechanical reasons or pipeline constraints
or because they may no longer be economic to continue to produce will be charged
the applicable monthly fixed production cost if they are completed in a zone
above 7,000 feet and $300 if they are completed in a zone below 7,000 feet. The
monthly fixed production cost will no longer be charged once a well is plugged
and abandoned. Each of these fixed production costs is subject to an annual
adjustment beginning April 1, 2001 in accordance with an industry standard set
forth in the accounting procedures in the transfer documents. Approximately 85%
of the 2,471 underlying wells are currently producing in excess of an average of
five Mcf per day. Production costs will be proportionately reduced based on
Eastern States' percentage working interest in the applicable well.
Eastern States Gathering and Compressing Charges. Eastern States will
deduct from gross proceeds an amount equal to its costs incurred to gather,
compress and process production from the underlying properties on Eastern
States' facilities plus an amount to reimburse Eastern States for depreciation
of the facilities and to provide a reasonable return on its investment in such
facilities. The amount of this charge will vary as changes occur in Eastern
States' investment in facilities associated with the underlying properties, as
well as when changes occur in the costs incurred by Eastern States to perform
such services.
Overhead. Generally, fees are allocated among operating and non-operating
interests. Because Eastern States has historically owned and operated almost
100% of its properties, it has not charged or allocated an overhead fee to the
non-operator. Pursuant to the transfer documents, Eastern States will deduct a
monthly overhead fee of $65 per producing well from the underlying properties,
including shut-in wells, subject to an annual adjustment beginning April 1, 2001
in accordance with an industry standard set forth in the accounting procedures
in the transfer documents. This fee will no longer be charged once a well is
plugged and abandoned. This fee will be proportionately reduced based on Eastern
States' percentage working interest in the applicable well.
Development Costs and Drilling Overhead. Eastern States will deduct all
development costs in calculating net proceeds attributable to the underlying
properties, plus a drilling overhead fee of $36,000 for each well drilled or
deepened to a deeper zone on or after September 1, 1999, subject to an annual
adjustment beginning April 1, 2001 in accordance with an industry standard set
forth in the accounting procedures in the transfer documents. Drilling costs
will fluctuate seasonally as a result of Eastern States' weather-related
concentration of drilling activity in the period from April to October. The
drilling overhead fee will be proportionately reduced based on Eastern States'
percentage working interest in the applicable well.
Excess costs are the excess of costs over gross proceeds, plus interest
accrued on such excess amount at the prime rate. Therefore, if costs exceed
gross proceeds for a computation period, the trust will receive no payment for
that period, and excess costs, plus interest accrued at the prime rate, will be
carried over to the following month as a cost in determining the excess of gross
proceeds over costs for that following month.
Gross proceeds and costs are calculated on a cash basis, except that some
costs, primarily ad valorem taxes and expenditures of a material amount, may be
determined on an accrual basis. For convenience in complying with state tax
laws, the net profits interests were created by two separate transfer documents,
one for each of Kentucky and West Virginia, the two states in which the
underlying properties are located.
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Net proceeds are calculated separately for the underlying properties covered by
each transfer document, so excess costs in one state do not reduce net proceeds
from the other.
Any gains or losses from hedging activities by Eastern States will not
affect the calculation of net proceeds.
ADDITIONAL PROVISIONS
The trust is not liable to the owner of the underlying properties or the
operators for any operating, capital or other costs or liabilities attributable
to the underlying properties. The trustee is not obligated to return any cash
received from the net profits interests. Any overpayments made to the trust due
to adjustments to prior calculations of net proceeds or otherwise will reduce
future amounts payable to the trust until Eastern States recovers the
overpayments plus interest at the prime rate.
Eastern States must maintain books and records sufficient to determine the
amounts payable for the net profits interests. Quarterly and annually, Eastern
States must deliver to the trustee a statement of the computation of the net
proceeds for each computation period. Eastern States will cause the annual
computation of net proceeds to be audited. The audit cost will be borne by the
trust.
As discussed under "The Underlying Properties -- Sale and Abandonment of
Underlying Properties; Sale of Net Profits Interests," Eastern States may convey
any or all of the underlying properties without the consent of the trust or the
unitholders. In this case, the trust's net profits interest must be paid by the
transferee to the extent attributable to the underlying properties transferred.
Neither the trust nor the unitholders are entitled to any of the proceeds from
any sale of the underlying properties. If, however, the net profits interests
are sold with the underlying properties, the trust will receive the proceeds
attributable to the sale of its net profits interests.
FEDERAL INCOME TAX CONSEQUENCES
This section discusses all the material federal income tax consequences of
the ownership and sale of trust units. Many aspects of federal income taxation
that may be relevant to a particular taxpayer or to some types of taxpayers
subject to specific tax treatment are not addressed. In addition, the tax laws
can and do change regularly, and any future changes could have an adverse effect
on the ownership or sale of trust units. The trust will not request rulings from
the IRS dealing with the tax consequences of ownership of trust units. Instead
the trust will rely on the opinion of Andrews & Kurth L.L.P. regarding the
classification of the trust and the federal income tax consequences described
below. Andrews & Kurth L.L.P. believes that its opinion is in accordance with
the present position of the IRS regarding grantor trusts. The opinion is not
binding on the IRS or the courts, however, and no assurance can be given that
the IRS or the courts will agree with it.
This discussion is based on current provisions of the Internal Revenue
Code, existing and proposed regulations thereunder and current administrative
rulings and court decisions, all of which are subject to changes that may or may
not be retroactively applied. Some of the applicable provisions of the Internal
Revenue Code have not been interpreted by the courts or the IRS. Currently
pending proposed Federal tax legislation may also, under certain circumstances,
have a material effect on a unitholder.
As a consequence, each prospective unitholder should consult his own tax
advisor with respect to his particular circumstances including his alternative
minimum tax circumstances.
SUMMARY OF LEGAL OPINIONS
Andrews & Kurth L.L.P. is of the opinion that, for federal income tax
purposes:
- the trust will be treated as a grantor trust and not as a partnership or
a corporation; and
- the income from the net profits interests will be royalty income subject
to an allowance for depletion.
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Andrews & Kurth L.L.P. advises that, unless noted otherwise, legal
conclusions stated in this section constitute its opinion.
Because no ruling is being requested from the IRS with respect to the trust
or trust unitholders, the IRS could challenge these opinions and statements,
which do not bind the IRS or the courts. The IRS could win in court if it did
challenge these matters.
CLASSIFICATION AND TAXATION OF THE TRUST
In the opinion of Andrews & Kurth L.L.P., under current law, the trust will
be taxable as a grantor trust. As a grantor trust, the trust will not be subject
to tax at the trust level. For tax purposes, the grantors, who in this case are
the trust unitholders, will be considered to own the trust's income and
principal as though no trust were in existence. A grantor trust simply files an
information return, reporting all items of income or deduction which must be
included in the tax returns of the trust unitholders based on their respective
accounting methods and taxable years without regard to the accounting method and
tax year of the trust. If, contrary to the opinion of Andrews & Kurth L.L.P.,
the trust were determined to be a business entity, it would be taxable as a
partnership unless it elected to be taxed as a corporation. The principal tax
consequence of the trust's being treated as a partnership would be that all
trust unitholders would report their share of income from the trust on the
accrual method of accounting regardless of their own method of accounting.
DIRECT TAXATION OF TRUST UNITHOLDERS
Because the trust will be treated as a grantor trust for federal income tax
purposes, each trust unitholder will be taxed directly on his share of trust
income and will be entitled to claim his share of trust deductions. Each trust
unitholder will recognize taxable income when the trust receives or accrues it,
even if it is not distributed until later. Trust unitholders will report their
share of trust income and expenses consistent with their own method of
accounting and their own tax year.
REPORTING OF TRUST INCOME AND EXPENSES
The trust will make quarterly distributions to unitholders of record on
each quarterly record date established for that distribution. The terms of the
trust agreement, as described below, seek to assure to the extent practicable
that income attributable to distributions will be reported to the unitholder who
receives the distributions, assuming that he is the owner of record on the
quarterly record date established for the distribution. However, a unitholder
will not receive the cash giving rise to that income in all situations. For
example, if the trustee establishes a reserve or borrows money to satisfy
liabilities of the trust, income associated with the cash used to establish that
reserve or to repay that liability must be reported by the unitholder, even
though that cash is not distributed to him.
The trust will allocate income and deductions to unitholders based on
record ownership at quarterly record dates established for distributions to the
unitholders. The impact of this allocation method will be to treat the taxable
income of the trust for a particular quarter as income to unitholders of record
for that quarter unless otherwise advised by counsel. It is unknown whether the
IRS will accept that allocation or will seek to require income and deductions of
the trust to be determined and allocated daily or on some other basis, possibly
retroactively to the date of the consummation of this offering. If the IRS were
successful in doing so, trust income might be taxed to trust unitholders other
than those who received the distribution relating to that income. Also, an
accrual basis trust unitholder might realize royalty income in a tax year
earlier than that reported by the trustee.
ROYALTY INCOME AND DEPLETION
In the opinion of Andrews & Kurth L.L.P. the income from the net profits
interests will be royalty income qualifying for an allowance for depletion. The
depletion allowance must be computed separately by each trust unitholder for
each oil or gas property, within the meaning of Section 614 of the Internal
Revenue Code. Andrews & Kurth L.L.P. understands that the IRS is presently
taking the position that a
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net profits interest carved from multiple properties is a single property for
depletion purposes. Accordingly, the trust intends to take the position that
each net profits interest transferred to the trust by a conveyance is a single
property for depletion purposes. The trust will change this position if a
different method is established by the IRS or the courts.
The deduction for depletion is determined annually and is the greater of
cost depletion or, if allowable, percentage depletion. Royalty income from
production attributable to trust units owned by independent producers will
qualify for percentage depletion. An individual or entity with production of the
equivalent of not more than 1,000 barrels of oil per day is an independent
producer. Percentage depletion is a statutory allowance equal to 15% of the
gross income from production from a property. Percentage depletion is subject to
a net income limitation of 100% of the taxable income from the property,
computed without regard to depletion deductions and some loss carrybacks. The
depletion deduction attributable to percentage depletion for a taxable year is
limited to 65% of the taxpayer's taxable income for the year before allowance of
independent producers percentage depletion and some loss carrybacks. Unlike cost
depletion, percentage depletion is not limited to the adjusted tax basis of the
property, although it reduces the adjusted tax basis, but not below zero.
Eastern States believes that trust unitholders who purchase trust units in
this offering will derive a substantially greater benefit from cost depletion
than from percentage depletion.
In computing cost depletion for each property for any year, the allowance
for the property is calculated by dividing the adjusted tax basis of the
property at the beginning of the year by the estimated total number of Bbls of
oil or Mcf of natural gas recoverable from the property. This amount is then
multiplied by the number of Bbls of oil or Mcf of natural gas produced and sold
from the property during the year. Cost depletion for a property cannot exceed
the adjusted tax basis of the property. Each trust unitholder will compute cost
depletion using his basis in his trust units. Information will be provided to
each trust unitholder reflecting how his basis should be allocated among each
property represented by his trust units. To the extent the depletion deduction
exceeds cash distributions per trust unit, that excess can be deducted from the
taxpayer's other sources of taxable income.
OTHER INCOME AND EXPENSES
It is anticipated that the trust's only other income will be interest
income earned on funds held as a reserve or pending distribution. Other trust
expenses will include any state and local taxes imposed on the trust and
administrative expenses of the trustee. Although the issue has not been finally
resolved, Andrews & Kurth L.L.P. believes that all or substantially all of those
expenses are deductible in computing adjusted gross income and, therefore, are
not the type of miscellaneous itemized deductions that are allowable only to the
extent that they total more than 2% of adjusted gross income.
ALTERNATIVE MINIMUM TAX
All taxpayers are subject to an alternative minimum tax. Alternative
minimum taxable income is the taxpayer's taxable income recomputed with various
adjustments plus items of tax preference. In the case of persons other than
independent producers, tax preferences include the excess of percentage
depletion deductions for an oil or natural gas property over the adjusted tax
basis of the property. Alternative minimum tax is the excess of a taxpayer's
tentative minimum tax on his alternative minimum taxable income for a tax year
over his regular tax for that year.
Because the effect of the alternate minimum tax varies depending upon each
trust unitholder's personal tax and financial position, each prospective
investor is advised to consult with his own tax advisor concerning the effect of
the alternate minimum tax on him.
UNRELATED BUSINESS TAXABLE INCOME
Some organizations that are generally exempt from tax under Internal
Revenue Code Section 501 are subject to tax on some types of business income
defined in Section 512 as unrelated business income. In
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the opinion of Andrews & Kurth L.L.P., the income of the trust will not be
unrelated business taxable income so long as the trust does not incur any debt
and the trust units are not debt-financed property within the meaning of Section
514(b). In general, a trust unit would be debt-financed only if the trust
unitholder incurs debt to acquire a trust unit or otherwise incurs or maintains
a debt that would not have been incurred or maintained if the trust unit had not
been acquired.
SALE OF TRUST UNITS
Generally, a trust unitholder will realize gain or loss on the sale or
exchange of his trust units measured by the difference between the amount
realized on the sale or exchange and his adjusted basis for the trust units.
Except to the extent of the depletion recapture amount described below, gain or
loss on the sale of trust units by a trust unitholder who is not a dealer of the
trust units will be a long-term capital gain, taxable at a maximum rate of 20%,
if the trust units have been held for more than 12 months. A trust unitholder's
initial basis in his trust units will be equal to the amount he paid for the
trust units. That basis will be reduced by deductions for depletion claimed by
the trust unitholder, but not below zero.
Upon the sale of the trust units, a trust unitholder must treat as ordinary
income his depletion recapture amount, which is an amount equal to the lesser of
the gain on the sale or the sum of the prior depletion deductions taken on the
trust units, but not in excess of the initial basis of the trust units. The IRS
could also take the position that a portion of the sales proceeds is ordinary
income to the extent of any accrued income at the time of the sale that was
allocable to the trust units sold even though the income had not been
distributed to the selling trust unitholder.
SALE OF NET PROFITS INTERESTS
A sale by the trust of a net profits interest will be treated for federal
income tax purposes as a sale of that net profits interest by the unitholder.
Thus, a unitholder will recognize gain or loss on a sale of a net profits
interest by the trust. A portion of that income will be treated as ordinary
income to the extent of depletion recapture.
TAXATION OF FOREIGN HOLDERS
Unless the election described below is made, a foreign holder, consisting
of a nonresident alien individual, foreign corporation, or foreign estate or
trust, will be subject to federal income withholding tax on his share of gross
royalty income from the net profits interests. The withholding tax will be at a
30% rate, or lower treaty rate if applicable and proper evidence is supplied to
the withholding agent, without any deductions. Gain realized on a sale of a
trust unit by a foreign holder will be subject to federal income tax only if:
- the gain is otherwise effectively connected with business conducted by
the foreign holder in the United States;
- the foreign holder is an individual who is present in the United States
for at least 183 days in the year of the sale;
- the foreign holder has at any time during the five-year period ending on
the date of sale owned more than a 5% interest in the trust; or
- the trust units cease to be regularly traded on an established securities
exchange.
Gain realized by a foreign holder upon the sale by the trust of all or any
part of the net profits interests would be subject to federal income tax.
Trust unitholders who are foreign holders may elect under Internal Revenue
Code Section 871 or Section 882 or similar provisions of applicable treaties to
treat income attributable to the net profits interests as effectively connected
with the conduct of a trade or business in the United States. The foreign holder
will then be taxed at regular federal income tax rates on the net income rather
than gross income attributable to the net profits interests, including gain
recognized on the disposition of trust units. Absent a treaty exception, the net
income of a corporate foreign holder which has made an election will also be
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subject to the branch profits tax imposed under Section 884 to the extent such
net income is not reinvested in a United States trade or business. To claim the
deductions allowable in computing net income, including cost depletion, an
electing foreign holder must file a United States income tax return. To avoid
tax withholding, an electing foreign holder must provide proper certificates or
other evidence to the withholding agent. Once made, the election is irrevocable
unless an applicable treaty allows the election to be made annually. The
election is applicable to all income and gain realized by the foreign holder on
any real property interests located in the United States, including those
interests held through partnerships, fixed investment trusts, and other
pass-through entities.
BACKUP WITHHOLDING
In general, distributions of trust income will not be subject to backup
withholding unless the trust unitholder is an individual or other noncorporate
taxpayer and he fails to furnish his taxpayer identification number to the
trustee in the manner required or he otherwise fails to comply with certain
reporting procedures.
TAX SHELTER REGISTRATION
Eastern States believes that the requirements for tax shelter registration
under Internal Revenue Code Section 6111 would be met if any trust unitholder's
investment base is substantially reduced by borrowing. To avoid any potential
penalty, the trust will be registered as a tax shelter with the IRS. The trustee
will furnish the tax shelter registration number to each trust unitholder. Each
trust unitholder must disclose this number by attaching Form 8271 to his tax
return.
ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS
INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED
BY THE IRS.
REPORTS
The trustee will furnish to trust unitholders of record quarterly and
annual reports to facilitate their computation of their tax liability. For a
further discussion of the trustee's reporting obligations, see "Description of
the Trust Units -- Periodic Reports."
STATE TAX CONSIDERATIONS
This section is a brief summary of the material state income tax and other
state tax considerations affecting the trust and the trust unitholders. No
attempt has been made in the following discussion to comment on all state tax
matters affecting the trust or trust unitholders. This discussion focuses on
trust unitholders who are individuals not residing in either Kentucky or West
Virginia, as applicable, and has only limited application to corporations,
estates, trusts or other trust unitholders subject to specialized tax treatment,
such as tax-exempt institutions, IRAs, REITs or mutual funds. Accordingly, each
prospective trust unitholder should consult, and should depend on, his own tax
advisor in analyzing the particular state and local tax consequences to him of
an investment in the trust.
The trust will not request rulings from the West Virginia or Kentucky state
tax authorities dealing with the state tax consequences of ownership of trust
units. Instead, the trust will rely on the opinion of Goodwin & Goodwin
regarding the West Virginia state tax consequences described below and on the
opinion of Vorys, Sater, Seymour and Pease LLP regarding the Kentucky state tax
consequences described below.
Goodwin & Goodwin, LLP believes that its opinion is in accordance with the
position of the West Virginia state tax authorities regarding grantor trusts.
This opinion is not binding on the West Virginia state tax authorities or the
courts and we cannot assure you that the West Virginia state tax authorities or
the courts will agree with it.
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Vorys, Sater, Seymour and Pease LLP believes that its opinion is in
accordance with the position of the Kentucky state tax authorities regarding
grantor trusts. This opinion is not binding on the Kentucky state tax
authorities or the courts and we cannot assure you that the Kentucky state tax
authorities or the courts will agree with it.
INCOME TAX CONSIDERATIONS
The trust will own net profits interests burdening oil and gas properties
located in the states of Kentucky and West Virginia. These states impose income
taxes on residents and, for income from sources within these states, including
income from properties located in these states, nonresidents. A trust unitholder
may be required to file state income tax returns and/or to pay taxes in these
states and may be subject to penalties for failure to comply with these
requirements. Trust unitholders may also be subject to taxation by their state
of residence on income derived from the trust.
The income tax laws of Kentucky and West Virginia are based on federal
income tax laws. Assuming the trust is taxed as a grantor trust for federal
income tax purposes, the trust will not be subject to Kentucky or West Virginia
state income taxation but the trust unitholders will be subject to income tax in
both of these states on their share of income from the net profits interests
burdening properties located in that state. The trustee will provide information
concerning the trust sufficient to identify the income of the trust allocable to
each state. Individual nonresident trust unitholders with West Virginia adjusted
gross income from West Virginia sources in excess of the sum of West Virginia
personal exemptions are required to file a West Virginia state income tax
return. Individuals are currently allowed a West Virginia personal exemption of
$2,000 for each exemption allowed for federal income tax purposes. Individual
nonresident trust unitholders with gross income from Kentucky sources and $5,000
of total gross income must file a Kentucky state income tax return. It is
uncertain whether trust unitholders who are nonresidents of Kentucky or West
Virginia will be taxed in these states on gains from sales of trust units.
West Virginia imposes a withholding tax on distributions made to
nonresident individuals by an entity that is treated as a conduit of its income
for tax purposes. The trust does not believe it is an entity that is required to
withhold West Virginia taxes from distributions to trust unitholders who are not
West Virginia residents and does not intend to do so unless counsel advises that
such withholding is required. The trust would, if required, withhold 4% of the
taxable income of each nonresident trust unitholder attributable to West
Virginia sources. Distributions to trust unitholders are not currently subject
to Kentucky withholding tax. If Kentucky enacts a nonresident withholding tax,
the trust may be required to withhold taxes from distributions made to
nonresident unitholders attributable to Kentucky source income. Taxes withheld
by the trust from a trust unitholder would be treated as a distribution to that
trust unitholder and allowed as a credit against that trust unitholder's state
tax liability.
PROBATE AND PROPERTY CONSIDERATIONS
The trust units may constitute real property or an interest in real
property under the inheritance, estate and probate laws of Kentucky or West
Virginia. If the trust units are held to be real property or an interest in real
property under the laws of a state in which the underlying properties are
located, the trust unitholders may be subject to devolution, probate and
administration laws, and inheritance or estate and similar taxes, under the laws
of that state.
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ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974 regulates pension,
profit-sharing and other employee benefit plans to which it applies. ERISA also
contains standards for persons who are fiduciaries of those plans. In addition,
the Internal Revenue Code provides similar requirements and standards which are
applicable to qualified plans, which include these types of plans and to
individual retirement accounts, whether or not subject to ERISA.
A fiduciary of a qualified plan should carefully consider fiduciary
standards under ERISA regarding the qualified plan's particular circumstances
before authorizing an investment in trust units. A fiduciary should consider
- whether the investment satisfies the prudence requirements of Section
404(a)(1)(B) of ERISA;
- whether the investment satisfies the diversification requirements of
Section 404(a)(1)(C) of ERISA; and
- whether the investment is in accordance with the documents and
instruments governing the qualified plan as required by Section
404(a)(1)(D) of ERISA.
A fiduciary should also consider whether an investment in trust units might
result in direct or indirect nonexempt prohibited transactions under Section 406
of ERISA and Internal Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must determine whether
there are plan assets in the transaction. On November 13, 1986, the Department
of Labor published final regulations concerning whether or not a qualified
plan's assets would be deemed to include an interest in the underlying assets of
an entity for purposes of the reporting, disclosure and fiduciary responsibility
provisions of ERISA and analogous provisions of the Internal Revenue Code. These
regulations provide that the underlying assets of an entity will not be
considered "plan assets" if the equity interests in the entity are a publicly
offered security. Eastern States expects that at the time of the sale of the
trust units in this offering, they will be publicly offered securities.
Fiduciaries, however, will need to determine whether the acquisition of trust
units is a nonexempt prohibited transaction under the general requirements of
ERISA Section 406 and Internal Revenue Code Section 4975.
The prohibited transaction rules are complex, and persons involved in
prohibited transactions are subject to penalties. For that reason, potential
qualified plan investors should consult with their counsel to determine the
consequences under ERISA and the Internal Revenue Code of their acquisition and
ownership of trust units.
DESCRIPTION OF THE TRUST AGREEMENT
The following information and the information included under "Description
of the Trust Units" summarize the material information contained in the trust
agreement. This summary may not contain all the information that is important to
you. For more detailed provisions concerning the trust, you should read the
trust agreement. A copy of the trust agreement is filed as an exhibit to the
registration statement. See "Available Information."
CREATION AND ORGANIZATION OF THE TRUST; AMENDMENTS
Eastern States will create the net profits interests and transfer them to
the trust in exchange for
trust units. The transfers of the net profits interests will be effective as of
September 1, 1999.
Eastern States organized the trust under the Delaware Business Trust Act to
acquire and hold the net profits interests for the benefit of the trust
unitholders under a trust agreement among Eastern States, the property trustee
and the Delaware trustee. Neither the trust nor the property trustee has any
control over or responsibility for costs relating to the operation of the
underlying properties. Eastern States has no contractual commitments to the
trust to conduct further drilling on or to maintain its ownership interest in
any of these properties. For a description of the underlying properties and
other information relating to them, see "The Underlying Properties."
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The beneficial interest in the trust is divided into 10,500,000 trust
units. Each of the trust units represents an equal undivided beneficial interest
in the assets of the trust. You will find additional information concerning the
trust units in "Description of the Trust Units."
Amendment of the trust agreement requires a vote of holders of 66 2/3% or
more of the outstanding trust units. However, no amendment may:
- increase the power of the property trustee to engage in business or
investment activities;
- alter the rights of the trust unitholders as among themselves; or
- permit the property trustee to distribute the net profits interests in
kind.
Provided that they do not adversely affect the interests of the trust
unitholders, the following amendments do not require the vote of trust
unitholders:
- correcting any ambiguities;
- correcting defects and inconsistencies; and
- changing the name of the trust.
ASSETS OF THE TRUST
The assets of the trust consist of net profits interests and any cash and
temporary investments being held for the payment of expenses and liabilities or
for distribution to the trust unitholders.
DUTIES AND LIMITED POWERS OF THE PROPERTY TRUSTEE
The duties of the property trustee are specified in the trust agreement and
by the laws of the State of Delaware. The property trustee's principal duties
consist of:
- collecting cash attributable to the net profits interests;
- paying expenses, charges and obligations of the trust from the trust's
cash and assets;
- distributing distributable cash to the trust unitholders;
- furnishing trust unitholders with information necessary for federal and
state tax purposes; and
- taking any action it deems necessary and advisable to best achieve the
purposes of the trust.
If a trust liability is contingent or uncertain in amount or not yet
currently due and payable, the property trustee may create a cash reserve to pay
for the liability. If the property trustee determines that the cash on hand and
the cash to be received is insufficient to cover the trust's liability, the
property trustee may borrow funds required to pay the liabilities. The property
trustee may borrow the funds from any person, including itself. The property
trustee may also mortgage the assets of the trust to secure payment of the
indebtedness. If the property trustee borrows funds, the trust unitholders will
not receive distributions until the borrowed funds are repaid.
Each quarter, the property trustee will pay trust obligations and expenses
and distribute to the trust unitholders the remaining cash received from the net
profits interests. The cash held by the property trustee as a reserve against
future liabilities or for distribution at the next distribution date must be
invested in:
- interest bearing obligations of the United States government;
- repurchase agreements secured by interest-bearing obligations of the
United States government;
- money market mutual funds; or
- bank certificates of deposit.
The trust may not acquire any asset except the net profits interests, cash
and temporary cash investments, and it may not engage in any investment activity
except investing cash on hand.
At the request of Eastern States, the property trustee must sell for cash
the net profits interests relating to the underlying properties sold by Eastern
States to an unaffiliated third party. However, these sales are required only if
the net profits interests sold do not exceed $3 million in any calendar year or
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$20 million on an aggregate basis for the life of the trust. Upon such a sale,
Eastern States will, or will cause the purchaser to, pay to the trust the
portion of the purchase price allocable to the net profits interests sold, less
allocable expenses of the sale, including attorneys' fees.
The property trustee may sell the net profits interests in any of the
following circumstances:
- the sale does not involve trust assets of which the aggregate
standardized measure exceeds $30 million and is in the best interests of
the trust unitholders and a majority of the trust units represented at a
meeting of the trust unitholders where a quorum is present approve the
sale; or
- the sale involves trust assets of which the aggregate standardized
measure exceeds $30 million and is in the best interests of the trust
unitholders and holders representing at least 66 2/3% of the outstanding
trust units approve the sale.
Upon dissolution of the trust the property trustee must sell the net
profits interests. No trust unitholder approval is required in this event. The
trustee will distribute the net proceeds from any sale of the net profits
interests to the trust unitholders after payment of all liabilities of the trust
in accordance with law.
The property trustee may require any trust unitholder to dispose of his
trust units if an administrative or judicial proceeding seeks to cancel or
forfeit any of the property in which the trust holds an interest because of the
nationality or any other status of that trust unitholder. If a trust unitholder
fails to dispose of his trust units, the property trustee has the right to
purchase them and to borrow funds to make that purchase.
The property trustee may agree to modifications of the terms of the
conveyances or to settle disputes involving the conveyances. The property
trustee may not agree to modifications or settle disputes involving the royalty
part of the conveyances if these actions would change the character of the net
profits interests in a way that the net profits interests become working
interests or that the trust becomes an operating business.
DUTIES AND LIMITED POWERS OF THE DELAWARE TRUSTEE
The duties of the Delaware trustee are specified in the trust agreement and
by the laws of the State of Delaware. The Delaware trustee's principal duties
are to execute, deliver, acknowledge and file all necessary documents and to
maintain all necessary records of the trust as required by the laws of the State
of Delaware.
Unless specifically authorized in writing by the property trustee and
consented to by the Delaware trustee, the Delaware trustee shall not participate
in any decisions or possess any authority regarding the administration of the
trust, the investment of the trust's property or distributions to trust
unitholders.
LIABILITIES OF THE TRUST
Because the trust does not conduct an active business and the property
trustee has minimal power to incur obligations, Eastern States expects that the
trust will only incur liabilities for routine administrative expenses. These
might include the trustee's fees and accounting, engineering, legal and other
professional fees.
RESPONSIBILITY AND LIABILITY OF THE PROPERTY TRUSTEE
Under the trust agreement, the property trustee is required to act in the
best interests of the trust unitholders at all times. The property trustee must
exercise the same judgment and care in supervising and managing the trust's
assets as persons of ordinary prudence, discretion and intelligence would
exercise.
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The property trustee will not make business decisions affecting the assets
of the trust. Therefore, substantially all of the property trustee's functions
under the trust agreement are expected to be ministerial in nature. The trust
agreement, however, provides that the trustee may:
- charge a fee for its services as trustee;
- retain funds to pay for future expenses and deposit them in its own
account;
- lend funds at commercial rates to the trust to pay the trust's expenses;
and
- reimburse itself from the trust for its out-of-pocket expenses.
For a description of the functions of the property trustee, see "-- Duties and
Limited Powers of the Property Trustee" above.
In discharging its duty to trust unitholders, the property trustee may act
in its discretion and will be liable to the trust unitholders only for fraud,
gross negligence or acts or omissions constituting bad faith. The property
trustee will not be liable for any act or omission of its agents or employees
unless the property trustee acted in bad faith or with gross negligence in their
selection and retention. The property trustee will be indemnified individually
or as property trustee for any liability or cost that it incurs in the
administration of the trust, except in cases of fraud, gross negligence or bad
faith. The property trustee will have a lien on the assets of the trust as
security for this indemnification and its compensation earned as property
trustee. The property trustee is entitled to indemnification from trust assets
or, to the extent that trust assets are insufficient, from Eastern States. Trust
unitholders will not be liable to the property trustee for any indemnification.
The property trustee may not cause the trust to incur any contractual
liabilities that are not limited to the assets of the trust and will be liable
for its failure to do so. For a description of the limitations on the liability
of trust unitholders, see "Description of the Trust Units -- Liability of Trust
Unitholders."
Delaware law permits the trust unitholders to file actions seeking other
remedies, including:
- removal of the trustees;
- specific performance;
- appointment of a receiver;
- an accounting by the property trustee to trust unitholders; and
- punitive damages.
CONDITIONAL RIGHT OF REPURCHASE
The trust agreement provides that Eastern States and any of its successors,
affiliates and transferees will retain the right to repurchase all, but not less
than all, outstanding trust units at any time during which 15% or less of the
outstanding trust units are owned by persons or entities other than Eastern
States and its affiliates. Subject to the following sentence, any such
repurchase would be at a price equal to the greater of
(1) the highest price at which Eastern States or any of its affiliates
acquired trust units during the 90 days immediately preceding the
determination date; and
(2) the average closing price of trust units on the NYSE for the 30
trading days immediately preceding the determination date.
If Eastern States or any of its affiliates acquires trust units, excluding an
acquisition from Eastern States or any affiliate, during the period that is
three trading days after the determination date at a price per trust unit
greater than that at which an acquisition was made during the 90-day period
referred to in clause (1) of the preceding sentence, then for purposes of clause
(1) of the preceding sentence the highest price used therein shall be such
greater price. The determination date is three trading days prior to the date
that notice of the exercise is delivered to trust unitholders. Any repurchase
would be conducted in accordance with applicable Federal and state securities
laws, including, without limitation, Rule 13e-4 of the Securities Exchange Act
of 1934 to the extent then applicable.
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If Eastern States elects to purchase all the trust units, Eastern States
and the property trustee will, prior to the date fixed for purchase, give all
unitholders of record not less than 15 days' nor more than 60 days' written
notice. The notice will specify the time and place of the repurchase, calling
upon each trust unitholder to surrender to Eastern States or its agent on the
repurchase date at the place designated in the notice its certificate or
certificates representing the number of trust units specified in the notices. On
or after the repurchase date, each holder of trust units must present and
surrender to Eastern States or its agent its certificates for its trust units at
the place designated and thereupon the purchase price of the trust units shall
be paid to or on the order of the person or entity whose name appears on the
certificate or certificates as the owner thereof. In no event may fewer than all
of the outstanding trust units represented by the certificates be repurchased,
excluding any units held by Eastern States and any of its affiliates.
If Eastern States and the property trustee give a notice of repurchase and
if, on or before the date fixed for repurchase, the funds necessary for the
repurchase shall have been set aside by Eastern States, separate and apart from
its other funds, in trust for the pro rata benefit of the holders of the trust
units then, notwithstanding that any certificate for the trust units has not
been surrendered, at the close of business on the repurchase date the holders of
units shall cease to be unitholders and shall have no interest in or claims
against Eastern States, the trust, the Delaware trustee or the property trustee
by virtue thereof and shall have no voting or other rights with respect to the
trust units, except the right to receive the purchase price payable upon
repurchase, without interest thereon and without any other distributions for
record dates after the date of notice of the repurchase, upon surrender and
endorsement, if required by Eastern States of their certificates. The trust
units evidenced thereby will no longer be held of record in the names of the
unitholders. Subject to applicable escheat laws, any monies so set aside by
Eastern States and unclaimed at the end of two years from the repurchase date
will revert to the general funds of Eastern States, after which reversion the
holders of units so noticed for repurchase may look only to the general funds of
Eastern States for the payment of the purchase price. Any interest accrued on
funds so deposited would be paid to Eastern States from time to time as
requested by Eastern States.
If Eastern States exercises and consummates its right of repurchase, then
at its option it may cause the trust to be terminated by providing written
notice thereof to the property trustee and the Delaware trustee. Within 30 days
following written notice of Eastern States' decision to terminate the trust, the
property trustee and the Delaware trustee must cause all net profits interests
and, subject to the rights of unitholders with respect to the receipt of
distributions for which a record date has been determined, all proceeds of
production attributable to the net profits interests and any other assets of the
trust to be transferred to Eastern States or its assignee, subject to the right
of the property trustee and Delaware trustee to create reasonable reserves in
connection with the liquidation of the trust.
DURATION OF THE TRUST; SALE OF NET PROFITS INTERESTS
The trust will dissolve if:
- the trust sells all of the net profits interests;
- annual net proceeds for West Virginia are less than $3.5 million for each
of two consecutive years after the year 2000;
- annual net proceeds for Kentucky are less than $3.5 million for each of
two consecutive years after the year 2000;
- the holders of 66 2/3% or more of the outstanding trust units vote in
favor of termination;
- Eastern States exercises its conditional right of repurchase; or
- a judicial dissolution of the trust occurs.
The property trustee would then sell all of the trust's assets, either by
private sale or public auction, and, after payment of liabilities of the trust,
distribute the net proceeds of the sale to the trust unitholders. Thereafter the
trust will terminate.
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DISPUTE RESOLUTION
Any dispute, controversy or claim that may arise between Eastern States and
the property trustee relating to the trust will be submitted to binding
arbitration before a tribunal of three arbitrators. The tribunal of three
arbitrators shall be selected as follows: one arbitrator selected by the
claimant; one arbitrator selected by the respondent; and one arbitrator mutually
selected by the other two arbitrators.
COMPENSATION OF THE PROPERTY TRUSTEE AND THE DELAWARE TRUSTEE
The property trustee's and the Delaware trustee's compensation will be paid
out of the trust's assets. For a further discussion of the trustee's
compensation, see "The Trust."
MISCELLANEOUS
The property trustee may consult with counsel, accountants, geologists and
engineers and other parties the property trustee believes to be qualified as
experts on the matters for which advice is sought. The property trustee will be
protected for any action it takes in good faith reliance upon the opinion of an
expert.
DESCRIPTION OF THE TRUST UNITS
Each trust unit is a unit of beneficial ownership in the trust and
represents an undivided beneficial interest in the assets of the trust. Each
trust unitholder has the same rights regarding each of his trust units as every
other trust unitholder has regarding his units. The trust will have 10,500,000
trust units outstanding upon completion of the offering.
DISTRIBUTIONS AND INCOME COMPUTATIONS
Each quarter, the property trustee will determine the amount of funds
available for distribution to the trust unitholders. Available funds are the
excess cash received by the trust from the net profits interests and other
sources that quarter, over the trust's liabilities for that quarter. Available
funds will be reduced by any cash the property trustee decides to hold as a
reserve against future liabilities. Trust unitholders that own their trust units
on the record date, which is the 15th day of the third calendar month after the
end of the respective quarter, will receive a quarterly distribution no later
than the 25th day of the third month after the end of the respective quarter.
The first distribution will be made on or before December 25, 1999 to trust
unitholders owning trust units on December 15, 1999 for the production period
September 1, 1999 through September 30, 1999. The second distribution will be
made on or before March 25, 2000 to trust unitholders owning trust units on
March 15, 1999 for the production period October 1, 1999 through December 31,
1999.
Unless otherwise advised by counsel, the property trustee will treat the
income and expenses of the trust for each quarter as belonging to the trust
unitholders of record on the record date for that quarter. For a further
description of the income tax treatment of unit ownership, see "Federal Income
Tax Consequences" and "State Tax Considerations."
TRANSFER OF TRUST UNITS
Trust unitholders may transfer their trust units by sending their trust
unit certificate to the property trustee along with a transfer form that is
properly completed. The property trustee will not require either the transferor
or transferee to pay a service charge for any transfer of a trust unit. The
property trustee may require payment of any tax or other governmental charge
imposed for a transfer. The property trustee may treat the registered owner of
any trust unit as shown by its records as the owner of the trust unit. The
property trustee will not be considered to know about any claim or demand on a
trust unit by any party except the record owner. A person who acquires a trust
unit after any record date will not be entitled to the distribution relating to
that record date. Delaware law will govern all matters affecting the title,
ownership, warranty or transfer of trust units.
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PERIODIC REPORTS
No later than 120 days following the end of each year, the property trustee
will mail to the trust unitholders an annual report containing audited financial
statements of the trust.
The property trustee will file all required trust federal and state income
tax and information returns. The property trustee will prepare and mail to trust
unitholders annually reports that trust unitholders need to report their share
of the income and deductions of the trust.
Each trust unitholder and his representatives may examine, for any proper
purpose and during reasonable business hours, the records of the trust and the
property trustee.
LIABILITY OF TRUST UNITHOLDERS
Under the Delaware Business Trust Act, trust unitholders will be entitled
to the same limitation of personal liability extended to stockholders of private
corporations for profit under the General Corporation Law of the State of
Delaware.
VOTING RIGHTS OF TRUST UNITHOLDERS
Trust unitholders have more limited voting rights than those of
stockholders of most public corporations. For example, there is no requirement
for annual meetings of trust unitholders or for annual or other periodic
re-elections of the property trustee.
The property trustee or trust unitholders owning at least 15% of the
outstanding trust units may call meetings of trust unitholders. Meetings must be
held in Fort Worth, Texas. The property trustee must send written notice of the
time and place of the meeting and the matters to be acted upon to all of the
trust unitholders at least 20 days and not more than 60 days before the meeting.
Trust unitholders representing a majority of trust units outstanding must be
present or represented to have a quorum. Each trust unitholder is entitled to
one vote for each trust unit owned.
Under the trust agreement, a matter is approved by the vote of a majority
of the trust units held by the trust unitholders at a meeting where there is a
quorum. This is true, even if a majority of the total trust units did not
approve it. The affirmative vote of the holders of 66 2/3% of the outstanding
trust units is required to:
- dissolve the trust;
- amend the trust agreement for matters that adversely affect the right of
trust unitholders in a material respect; or
- approve the sale of all or any material part of the assets of the trust.
The property trustee must consent before all or any part of the trust
assets can be sold except in connection with the termination of the trust or
limited sales directed by Eastern States in conjunction with its sale of
underlying properties. The property trustee may be removed, with or without
cause, by the vote of the holders of a majority of the outstanding trust units.
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COMPARISON OF TRUST UNITS AND COMMON STOCK
You should be aware of the following ways in which an investment in trust
units is different from an investment in common stock of a corporation.
<TABLE>
<CAPTION>
TRUST UNITS COMMON STOCK
----------- ------------
<S> <C> <C>
Voting Limited voting rights. Corporate statutes provide
specific voting rights to
stockholders on electing
directors and major corporate
transactions.
Income Tax The trust is not subject to Corporations are taxed on
tax; trust unitholders are their income, and their
directly subject to income stockholders are taxed on
tax on their proportionate dividends received.
share of trust net income,
adjusted for tax deductions.
Distributions Substantially all trust cash Stockholders receive
receipts are distributed to dividends at the discretion
trust unitholders. of the board of directors.
Business and Assets Interest is limited to A corporation conducts an
specific assets with a finite active business for an
economic life. unlimited term and can
reinvest its earnings and
raise additional capital to
expand.
Fiduciary Duties To the extent provided in the Officers and directors have a
trust agreement, the property fiduciary duty of loyalty to
trustee has a fiduciary duty stockholders and a duty to
to the trust unitholders. use due care in management
Eastern States does not owe and administration of a
the trust unitholders a corporation.
fiduciary duty.
</TABLE>
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UNDERWRITING
Under the terms and subject to the conditions contained in the underwriting
agreement, the form of which is filed as an exhibit to the registration
statement, the underwriters named below, for whom Lehman Brothers Inc., Salomon
Smith Barney Inc., PaineWebber Incorporated, CIBC World Markets Corp., Credit
Suisse First Boston Corporation, Dain Rauscher Wessels, a division of Dain
Rauscher Incorporated, Donaldson, Lufkin & Jenrette Securities Corporation, A.G.
Edwards & Sons, Inc., and McDonald Investments Inc. are acting as
representatives, have agreed to purchase from Eastern States, and Eastern States
has agreed to sell to each underwriter, the number of trust units set forth
opposite the name of such underwriter below:
<TABLE>
<CAPTION>
NUMBER OF
TRUST UNITS
UNDERWRITERS -----------
<S> <C>
Lehman Brothers Inc. .......................................
Salomon Smith Barney Inc. ..................................
PaineWebber Incorporated....................................
CIBC World Markets Corp. ...................................
Credit Suisse First Boston Corporation......................
Dain Rauscher Wessels.......................................
Donaldson, Lufkin & Jenrette Securities Corporation.........
A.G. Edwards & Sons, Inc. ..................................
McDonald Investments Inc. ..................................
---------
Total............................................. 7,875,000
=========
</TABLE>
Eastern States has granted to the underwriters an option to purchase up to
an additional 1,181,250 trust units, exercisable solely to cover
over-allotments, at the initial public offering price, less the underwriting
discounts and commissions shown on the cover page of this prospectus. Such
option may be exercised at any time until 30 days after the date of the
underwriting agreement. To the extent that the option is exercised, each
underwriter will be committed, subject to conditions specified in the
underwriting agreement, to purchase a number of the additional trust units that
is proportionate to such underwriter's initial commitment as indicated on the
preceding table.
The following table shows the per trust unit and total underwriting
discounts and commissions to be paid to the underwriters by Eastern States.
These amounts are shown assuming both no exercise and full exercise of the
underwriters' option to purchase 1,181,250 additional units.
<TABLE>
<CAPTION>
PAID BY EASTERN STATES
---------------------------
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per trust unit..............................................
Total.......................................................
</TABLE>
The underwriters propose to offer the trust units to the public at the
initial public offering price set forth on the cover page of this prospectus and
to certain dealers at such initial public offering price less a selling
concession not in excess of $ per trust unit. The underwriters may allow,
and such dealers may reallow, a concession not in excess of $ per trust unit
to certain other underwriters or to certain other brokers or dealers. After the
initial offering of the trust units to the public, the offering price and other
selling terms may from time to time be changed by the representatives.
The underwriting agreement provides that the obligations of the
underwriters to pay for and accept delivery of the trust units offered hereby
are subject to approval of certain legal matters by counsel and to other
specified conditions, including the condition that no stop order suspending the
effectiveness of the registration statement is in effect and no proceedings for
such purpose are pending or threatened by the SEC, and that there has been no
material adverse change or development involving a prospective material adverse
change in the condition of the trust or the underlying properties from that set
forth in the
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<PAGE> 73
registration statement otherwise than as set forth or contemplated in this
prospectus, and that certificates, opinions and letters specified in the
underwriting agreement have been received from Eastern States and its counsel.
The underwriters are obligated to take and pay for all trust units (other than
those covered by the underwriters' over-allotment option described below) if any
such trust units are taken.
Eastern States and the trust have agreed in the underwriting agreement to
indemnify the underwriters against civil liabilities to the extent specified in
that agreement, including liabilities under the Securities Act, and to
contribute to payments that the underwriters may be required to make for such
liabilities. The trust's indemnity obligations are limited to the assets of the
trust, and neither the trustee nor any unitholder will have any obligation to
indemnify the underwriters.
Eastern States has agreed that they will not, without the prior written
consent of Lehman Brothers Inc., during the 180 days following the date of this
prospectus, (1) offer for sale, sell, pledge or otherwise dispose of (or enter
into any transaction or device which is designed to, or could be expected to,
result in the disposition by any person at any time in the future of) any trust
units or any securities that are convertible into, or exercisable or
exchangeable for, or that represent the right to receive, trust units, or (2)
enter into any swap or other derivatives transaction that transfers to another,
in whole or in part, any of the economic benefits or rights of ownership of such
trust units.
The underwriters have advised Eastern States that they do not intend to
confirm any sales to accounts over which they exercise discretionary authority.
Until the distribution of the trust units is completed, the rules of the
SEC may limit the ability of the underwriters and certain selling group members
to bid for and purchase trust units. As an exception to these rules, the
representatives are permitted to engage in certain transactions that stabilize
the price of the trust units. Such transactions may consist of bids or purchases
for the purpose of pegging, fixing or maintaining the price of the trust units.
In addition, if the representatives over-allot, that is, if they sell more
trust units than are set forth on the cover page of this prospectus, and thereby
create a short position in the trust units in connection with the offering, the
representatives may reduce that short position by purchasing trust units in the
open market. The representatives may also elect to reduce any short position by
exercising all or part of the over-allotment option described herein.
In addition, if the underwriters purchase trust units in the open market
for the account of the underwriting syndicate and the trust units purchased can
be traced to a particular underwriter or selling group member, the underwriting
syndicate may impose a "penalty bid" on the selling underwriter or member for
reselling trust units back to the syndicate. The penalty bid can be a
requirement that the underwriter purchase the trust units it sold at the cost
price to the syndicate or a requirement that the underwriter or selling group
member repay to the syndicate account the selling concession it earned at the
sale of the trust units. As a result, an underwriter or selling group member
and, in turn brokers, may lose the fees that they otherwise would have earned
from a sale of the trust units if their customer resells the trust units while
the penalty bid is in effect. The imposition of a penalty bid might have an
effect on the price of the trust units if it discouraged resales of trust units
by purchasers in the offering.
In general, purchases of a security for the purpose of stabilization or to
reduce a syndicate short position could cause the price of the security to be
higher than it might otherwise be in the absence of such purchases. The
imposition of a penalty bid might have an effect on the price of a security to
the extent that it were to discourage resales of the security by purchasers in
the offering.
Neither Eastern States, the trust nor any of the underwriters makes any
representation or prediction as to the direction or magnitude of any effect that
the transactions described above may have on the price of the trust units. In
addition, neither Eastern States, the trust nor any of the underwriters makes
any representation that the representatives will engage in such transactions or
that such transactions, once commenced, will not be discontinued without notice.
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Prior to the offering, there has been no public market for the trust units.
The initial public offering price was negotiated between Eastern States and the
representatives. The factors considered in determining the initial public
offering price of the trust units include prevailing market conditions,
estimates of distributions to trust unitholders and the overall quality of the
underlying properties. The initial public offering price set forth on the cover
page of this prospectus should not, however, be considered an indication of the
actual value of the trust units. Such price will be subject to change as a
result of market conditions and other factors. There can be no assurance that an
active trading market will develop for the trust units or that the trust units
will trade in the public market subsequent to the offering at or above the
initial public offering price.
Eastern States estimates that the total expenses of the offering, other
than underwriting discounts and commissions, will be approximately $1.5 million.
The trust has applied to have the trust units listed on the NYSE under the
symbol "ANG."
A prospectus may be made available in electronic format on an Internet
website maintained by Fidelity Investments, which is expected to act as one of
the dealers in the offering.
Because it is expected that the National Association of Securities Dealers,
Inc. will view the trust units offered hereby as interests in a direct
participation program, the offering is being made in compliance with Rule 2810
of the NASD's Conduct Rules.
SELLING TRUST UNITHOLDER
Eastern States currently owns all of the 10,500,000 outstanding trust
units. It is offering 7,875,000 trust units in this offering, or 9,056,250 trust
units if the underwriters exercise their over-allotment option in full.
Eastern States may sell trust units, exchange them for oil and natural gas
properties or use them for other corporate purposes.
Prior to this offering there has been no public market for the trust units.
Eastern States cannot predict the effect on future market prices, if any, of
market sales of trust units or the availability of trust units for sale if it
disposes of its trust units. Nevertheless, sales of substantial amounts of trust
units in the public market could adversely affect prevailing market prices.
VALIDITY OF THE TRUST UNITS
Counsel for Eastern States and the trust, Andrews & Kurth L.L.P., Houston,
Texas will give the tax opinion described in the section of this prospectus
captioned "Federal Income Tax Consequences" and other matters. Richards, Layton
& Finger, P.A. will give a legal opinion as to the validity of the trust units.
Certain legal matters in connection with the trust units offered hereby will be
passed upon for the underwriters by Baker & Botts, L.L.P., Houston, Texas.
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EXPERTS
Information appearing in this prospectus regarding the August 31, 1999
estimated quantities of reserves of the underlying properties and net profits
interests owned by the trust, the future net revenues from those reserves and
their present value was prepared by Ryder Scott Company, L.P., independent
petroleum engineers.
Ernst & Young LLP, independent auditors, have audited the Statements of
Revenues and Direct Operating Expenses of the Underlying Properties of Eastern
States Oil and Gas, Inc. for each of the three years in the period ended
December 31, 1998, the Statement of Assets and Trust Corpus of Appalachian
Natural Gas Trust, formerly the Appalachian Basin Royalty Trust, as of August
19, 1999, the Consolidated Financial Statements of Eastern States Oil and Gas,
Inc. as of December 31, 1998 and 1997, and for each of the three years in the
period ended December 31, 1998, and the Consolidated Financial Statements of the
domestic operations of Blazer Energy Corp. for the year ended September 30,
1996, as set forth in their reports. We have included these financial statements
in the prospectus and elsewhere in the registration statement in reliance on
Ernst & Young LLP's reports, given on their authority as experts in accounting
and auditing.
AVAILABLE INFORMATION
The trust and Eastern States have filed with the SEC in Washington, D.C. a
registration statement, including all amendments, under the Securities Act of
1933 relating to the trust units. As permitted by the rules and regulations of
the SEC, this prospectus does not contain all of the information contained in
the registration statement and the exhibits and schedules to the registration
statement. You may read and copy the registration statement or other information
at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C.
20549. You may request copies of these documents, upon payment of a duplicating
fee, by writing to the SEC at the address in the previous sentence. To obtain
information on the operation of the public reference rooms you may call the SEC
at (800) SEC-0330. Eastern States' filings will also be available to the public
on the SEC Internet Web site at http://www.sec.gov.
Bank One, Texas, N.A. is the property trustee of the trust. The property
trustee's address is 500 Throckmorton, Suite 801, Fort Worth, Texas 76102,
Attention: Corporate Trust Department.
71
<PAGE> 76
GLOSSARY OF OIL AND NATURAL GAS TERMS
In this prospectus the following terms have the meanings specified below.
Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil
or other liquid hydrocarbons.
Bcf -- One billion cubic feet of natural gas.
Bcfe -- One billion cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
Btu -- A British Thermal Unit, a common unit of energy measurement.
Estimated Future Net Cash Flow -- The result of applying current prices of
oil and natural gas to estimated future production from oil and natural gas
proved reserves, reduced by estimated future expenditures, based on current
costs to be incurred, in developing and producing the proved reserves, excluding
overhead.
MBbl -- One thousand Bbl.
Mcf -- One thousand cubic feet of natural gas.
Mcfe -- One thousand cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
MMbtu -- One million Btus.
MMcf -- One million cubic feet of natural gas.
MMcfe -- One million cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
Natural Gas Revenue -- Includes revenue related to the sale of natural gas,
natural gas liquids and plant products.
Net Wells or Acres -- Determined by multiplying "gross" wells or acres by
the interest in such wells or acres represented by the underlying properties.
Net Profits Interest (also called a net overriding royalty interest) -- A
nonoperating interest that creates a share in gross production from an operating
or working interest in oil and gas properties. The share is measured by net
profits from the sale of production after deducting production and property
taxes, development and production costs and overhead.
NYMEX -- New York Mercantile Exchange, where futures and options contracts
for the oil and natural gas industry and some precious metals are traded.
Overriding Royalty Interest -- A royalty interest created or "carved" out
of a working or operating interest. Its term extends for the same term as the
working interest from which it is carved.
Proved Developed Reserves -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved Reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and natural gas reservoirs under existing economic and operating conditions.
The Securities and Exchange Commission definition of proved oil and gas
reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
72
<PAGE> 77
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
(1) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(2) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(3) Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (C) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
Proved Undeveloped Reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.
Reserve-to-Production Index -- An estimate, expressed in years, of the
total estimated proved reserves attributable to a producing property divided by
production from the property for the 12 months preceding the date as of which
the proved reserves were estimated.
Royalty Interest -- A real property interest entitling the owner to receive
a specified portion of the gross proceeds of the sale of oil and natural gas
production or, if the transfer document or conveyance creating the interest
provides, a specific portion of oil and natural gas produced, without any
deduction for the costs to explore for, develop or produce the oil and natural
gas. A royalty interest owner has no right to consent to or approve the
operation and development of the property, while the owners of the working
interest have the exclusive right to exploit the mineral on the land.
Standardized Measure of Discounted Future Net Cash Flows -- Also referred
to herein as "standardized measure." It is the present value of estimated future
net revenues computed by discounting estimated future net revenues at a rate of
10% annually. The Financial Accounting Standards Board requires disclosure of
standardized measure of discounted future net cash flows relating to proved oil
and gas reserve quantities, per paragraph 30 of Statement of Financial
Accounting Standards No. 69, as follows:
A standardized measure of discounted future net cash flows relating to an
enterprise's interests in (a) proved oil and gas reserves and (b) oil and gas
subject to purchase under long-term supply, purchase, or similar agreements and
contracts in which the enterprise participates in the operation of the
properties on which the oil or gas is located or otherwise serves as the
producer of those reserves shall be disclosed as of the end of the year. The
standardized measure of discounted future net cash flows relating to those two
types of interests in reserves may be combined for reporting purposes. The
following information shall be disclosed in the aggregate and for each
geographic area for which reserve quantities are disclosed:
a.Future cash inflows. These shall be computed by applying year-end prices
of oil and gas relating to the enterprise's proved reserves to the
year-end quantities of those reserves. Future price
73
<PAGE> 78
changes shall be considered only to the extent provided by contractual
arrangements in existence at year-end.
b.Future development and production costs. These costs shall be computed by
estimating the expenditures to be incurred in developing and producing
the proved oil and gas reserves at the end of the year, based on year-end
costs and assuming continuation of existing economic conditions. If
estimated development expenditures are significant, they shall be
presented separately from estimated production costs.
c.Future income tax expenses. These expenses shall be computed by applying
the appropriate year-end statutory tax rates, with consideration of
future tax rates already legislated, to the future pretax net cash flows
relating to the enterprise's proved oil and gas reserves, less the tax
basis of the properties involved. The future income tax expenses shall
give effect to tax deductions, tax credits and allowances relating to the
enterprise's proved oil and gas reserves.
d.Future net cash flows. These amounts are the result of subtracting future
development and production costs and future income tax expenses from
future cash inflows.
e.Discount. This amount shall be derived from using a discount rate of 10
percent a year to reflect the timing of the future net cash flows
relating to proved oil and gas reserves.
f.Standardized measure of discounted future net cash flows. This amount is
the future net cash flows less the computed discount.
Working Interest (also called an operating interest) -- A real property
interest entitling the owner to receive a specified percentage of the proceeds
of the sale of oil and natural gas production or a percentage of the production,
but requiring the owner of the working interest to bear the cost to explore for,
develop and produce such oil and natural gas. A working interest owner who owns
a portion of the working interest may participate either as operator or by
voting his percentage interest to approve or disapprove the appointment of an
operator and certain activities in connection with the development and operation
of a property.
74
<PAGE> 79
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
UNDERLYING PROPERTIES
Report of Independent Auditors............................ F-2
Statements of Revenues and Direct Operating Expenses for
the Years Ended December 31, 1996, 1997 and 1998 and
for the Eight Months Ended August 31, 1998, and 1999... F-3
Notes to Statements of Revenues and Direct Operating
Expenses............................................... F-4
APPALACHIAN NATURAL GAS TRUST
Report of Independent Auditors............................ F-8
Statement of Assets and Trust Corpus as of August 19,
1999................................................... F-9
Notes to Statement of Assets and Trust Corpus............. F-10
Pro Forma Statement of Assets and Trust Corpus
(Unaudited)............................................ F-11
Pro Forma Statement of Distributable Cash for the Year
Ended December 31, 1998 and for the Eight Months Ended
August 31, 1999 (Unaudited)............................ F-12
Notes to Pro Forma Statement of Distributable Cash
(Unaudited)............................................ F-13
</TABLE>
F-1
<PAGE> 80
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.
We have audited the accompanying statements of revenues and direct
operating expenses of the Underlying Properties of Eastern States Oil & Gas,
Inc. for each of the three years in the period ended December 31, 1998. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the statements referred to above present fairly, in all
material respects, the revenues and direct operating expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Vienna, Virginia
October 6, 1999, except for Note 5, as
to which the date is October 13, 1999
F-2
<PAGE> 81
UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
AND FOR THE EIGHT MONTHS ENDED AUGUST 31, 1998 AND 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
EIGHT MONTHS
FOR THE YEARS ENDED, ENDED AUGUST 31,
--------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues
Gas sales.................................. $54,877 $52,303 $41,835 $29,879 $25,594
Oil sales.................................. 677 531 242 157 230
------- ------- ------- ------- -------
Total.............................. 55,554 52,834 42,077 30,036 25,824
------- ------- ------- ------- -------
Direct Operating Expenses
Production and property taxes.............. 5,179 4,872 3,809 2,713 2,338
Production expenses........................ 6,300 5,106 3,603 2,401 2,401
------- ------- ------- ------- -------
Total.............................. 11,479 9,978 7,412 5,114 4,739
------- ------- ------- ------- -------
Excess of Revenues over Direct Operating
Expenses................................ $44,075 $42,856 $34,665 $24,922 $21,085
======= ======= ======= ======= =======
</TABLE>
See accompanying Notes to Statements of Revenues and Direct Operating Expenses.
F-3
<PAGE> 82
UNDERLYING PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
1. UNDERLYING PROPERTIES
The underlying properties (the "Underlying Properties") are predominantly
working interests in producing properties currently owned by Eastern States Oil
& Gas, Inc. (the "Company") in the Appalachian Basin in the states of West
Virginia and Kentucky. Effective September 1, 1999, the Company will convey an
80% net profits interests in 2,471 producing wells in Kentucky and West Virginia
and a 10% net profits interest in certain undeveloped properties in Kentucky and
West Virginia (together, the "Net Profits Interests") to the Appalachian Natural
Gas Trust (the "Trust"), formerly the Appalachian Basin Royalty Trust, excluding
certain specified interests. Estimated proved reserves attributable to the
Underlying Properties are approximately 1% oil and 99% natural gas, based on
discounted present value of estimated future net revenues as of August 31, 1999.
See Note 6.
All of the Underlying Properties were acquired by the Company from 1994
through 1998. Significant property acquisitions were made by the Company during
the three-year period presented in the accompanying financial statements. The
accompanying statements include the historical revenues and direct operating
expenses from these acquired properties for all years presented.
2. BASIS OF PRESENTATION
The statements of revenues and direct operating expenses of the Underlying
Properties were derived from the historical accounting records of the Company
(and prior owners for acquisitions occurring during the three-year period
presented), and are presented on the accrual basis of accounting before the
effects of conveyance of the Net Profits Interests. The point of sale for
revenue recognition is at the wellhead. Costs to transport and gather natural
gas have been deducted from the price paid at the wellhead. As a result,
production expenses exclude these costs. The statements do not include
depreciation, depletion and amortization, general and administrative or interest
expenses.
Royalty income of the Trust is determined based on an 80% net profits
interest percentage of net proceeds of the underlying wells and a 10% net
profits interest percentage of underlying leases. The computation of net profits
interest includes deductions for development costs. For the periods presented,
development costs (in thousands) were $12,024 in 1996 and $22,445 in 1997, none
in 1998 and none for the eight months ended August 31, 1999 since all wells
drilled in 1998 through August 31, 1999 have been excluded from the Underlying
Properties. In addition, the 1996 and 1997 development costs are only those
incurred by Eastern States and exclude development costs of Blazer Energy,
Corp., which owned a majority of the Underlying Properties prior to July 1,
1997, the effective acquisition date by Eastern States. Since the Company owns
greater than 97% working interest in the properties, it did not charge an
overhead fee to the properties in 1996 through 1998, but the trust will be
charged an overhead fee in the computation of trust income. Accordingly, royalty
income of the Trust will be materially different from the excess of revenues
over direct operating expenses from the Underlying Properties.
3. RELATED PARTY TRANSACTIONS
The Company sells approximately 68% of its natural gas production from the
Underlying Properties to the Company's affiliated marketing company, Statoil
Energy Services, Inc., generally at amounts approximating monthly market prices.
Sales from the Underlying Properties to the Company's marketing affiliate
Statoil Energy Services, Inc. were as follows (in thousands): $7,756, $27,227,
$27,966, $19,340, and $18,090 for the years 1996, 1997, 1998 and the eight
months ended August 31, 1998 and 1999, respectively.
F-4
<PAGE> 83
UNDERLYING PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES -- (CONTINUED)
4. CONTINGENCIES
The Company is involved in various legal actions and claims arising in the
normal course of business. Based upon its current assessment of the facts and
the law, management does not believe that any of these actions or claims are
material. However, these actions against the Company are subject to the
uncertainties inherent in any litigation.
5. SUBSEQUENT EVENT
On October 13, 1999, The Statoil Group -- Norway ("Statoil") announced
plans to seek a buyer for its U.S. natural gas and electric power production and
marketing unit, Statoil Energy, Inc. ("STEN") in connection with a corporate
restructuring process. The Statoil Group has announced its intentions to market
STEN as an integrated enterprise consisting of STEN's subsidiaries, including
Eastern States, involved in gas production, power production, energy marketing
and energy trading. However, the Statoil Group may determine that the sale of
individual assets or divisions, including Eastern States, is more appropriate.
If such a sale of Statoil Energy or Eastern States occurs, the Company cannot
assure that it will not adversely affect Eastern States.
6. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Proved oil and natural gas reserves of the Underlying Properties have been
estimated by Ryder Scott Company, L.P., independent petroleum engineers as of
August 31, 1999. Reserves for the years ended December 31, 1998 and 1997 were
internally prepared by the Company's petroleum engineers. Since the Company does
not have comparable reserve reports for periods prior to December 31, 1997 due
to its property acquisitions in 1996 and 1997, such estimates prior to December
31, 1997 have been internally developed by the Company's petroleum engineers by
adding back actual production volumes to arrive at estimated reserve balances at
December 31, 1995 and 1996. As a result of this method, the following tables
reflect no reserve estimate revisions for periods prior to 1998. Drilling
activities on these properties during 1996 and 1997 have represented development
of these proved reserves. The reserve estimates provided for the Underlying
Properties were calculated before the effects of conveying the Net Profits
Interests to the Trust. In accordance with Statement of Financial Accounting
Standards No. 69, estimates of future net revenues from proved reserves have
been prepared using year-end oil and natural gas prices and current costs to
produce and develop the proved reserves, excluding overhead. The standardized
measure of future net cash flows from oil and natural gas reserves is calculated
based on discounting such future net cash flows at an annual rate of 10%.
Year-end oil prices were $22.50 per barrel for 1996, $15.00 per barrel for 1997
and $9.00 per barrel for 1998. As of August 31, 1999, oil prices were $18.75 per
barrel. Year-end weighted average natural gas prices were $3.68 per Mcf for
1996, $2.57 per Mcf for 1997 and $2.71 per Mcf for 1998. As of August 31, 1999,
the weighted average natural gas price was $2.75 per Mcf.
F-5
<PAGE> 84
UNDERLYING PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES -- (CONTINUED)
6. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
<TABLE>
<CAPTION>
PROVED RESERVES GAS (MMCF) OIL (MBBLS)
- --------------- ---------- -----------
<S> <C> <C>
Balance, December 31, 1995.................................. 666,996 338
Revisions................................................. -- --
Extensions, discoveries and other additions............... 6,094 --
Production................................................ (19,318) (35)
Balance, December 31, 1996.................................. 653,772 303
Revisions................................................. -- --
Extensions, discoveries and other additions............... 11,167 --
Production................................................ (19,960) (31)
Balance, December 31, 1997.................................. 644,979 272
Revisions................................................. 63,187 20
Extensions, discoveries and other additions............... -- --
Production................................................ (19,040) (20)
Balance, December 31, 1998.................................. 689,126 272
Revisions................................................. 88,955 7
Extensions, discoveries and other additions............... -- --
Production................................................ (11,967) (19)
Balance, August 31, 1999.................................... 766,114 260
</TABLE>
PROVED DEVELOPED RESERVES
<TABLE>
<CAPTION>
GAS (MMCF) OIL (MBBLS)
---------- -----------
<S> <C> <C>
December 31, 1995........................................... 360,942 338
December 31, 1996........................................... 347,718 303
December 31, 1997........................................... 338,925 272
December 31, 1998........................................... 344,907 272
August 31, 1999............................................. 329,581 260
</TABLE>
F-6
<PAGE> 85
UNDERLYING PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES -- (CONTINUED)
6. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
The standardized measure of future net cash flows is not intended to
represent the fair value of the Underlying Properties. Numerous uncertainties
are inherent in estimating volumes and values of proved reserves and in
projecting future production rates and timing of development expenditures. Such
reserve estimates are subject to change as additional information becomes
available. The reserves actually recovered and the timing of production may be
substantially different from the original estimates. Also, because natural gas
prices are influenced by seasonal demand, use of year-end prices, as required by
the Financial Accounting Standards Board, may not be representative in
estimating future revenues or reserve data.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, EIGHT MONTHS
------------------------------------- ENDED AUGUST 31,
1996 1997 1998 1999
----------- ---------- ---------- ----------------
<S> <C> <C> <C> <C>
Future cash inflows...................... $ 2,320,789 $1,669,303 $1,874,485 $2,129,626
Future costs:
Production............................. (360,827) (313,269) (322,418) (373,705)
Development............................ (182,412) (172,966) (189,211) (284,973)
----------- ---------- ---------- ----------
Future net cash flows.................... 1,777,550 1,183,068 1,362,856 1,470,948
10% discount factor...................... (1,234,237) (821,460) (975,895) (1,103,671)
----------- ---------- ---------- ----------
Standardized measure of discounted future
net cash flows......................... $ 543,313 $ 361,608 $ 386,961 $ 367,277
=========== ========== ========== ==========
</TABLE>
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED
RESERVES
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, EIGHT MONTHS
------------------------------- ENDED AUGUST 31,
1996 1997 1998 1999
-------- --------- -------- ----------------
<S> <C> <C> <C> <C>
Standardized measure, beginning of period..... $367,873 $ 543,313 $361,608 $386,961
Revisions:
Prices and costs............................ 157,764 (174,524) 27,273 6,346
Quantity estimates.......................... -- -- 40,544 50,828
Accretion of discount....................... 53,688 54,732 29,835 31,078
Production rates and other.................. (4,978) (35,532) (21,242) 8,912
-------- --------- -------- --------
Net revisions............................ 206,474 (155,324) 76,410 97,164
Extensions, discoveries and other additions... 6,860 7,235 -- --
Production.................................... (44,075) (42,856) (34,665) (21,085)
Development costs............................. 6,181 9,240 (16,392) (95,763)
-------- --------- -------- --------
Net change............................... 175,440 (181,705) 25,353 (19,684)
-------- --------- -------- --------
Standardized measure, end of period........... $543,313 $ 361,608 $386,961 $367,277
======== ========= ======== ========
</TABLE>
F-7
<PAGE> 86
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.
We have audited the accompanying statement of assets and trust corpus of
the Appalachian Natural Gas Trust (formerly the Appalachian Basin Royalty Trust)
as of August 19, 1999. This financial statement is the responsibility of the
management of Eastern States Oil & Gas, Inc. Our responsibility is to express an
opinion on this financial statement based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statement is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the statement referred to above presents fairly, in all
material respects, the assets and trust corpus of the Appalachian Natural Gas
Trust as of August 19, 1999, in conformity with generally accepted accounting
principles.
ERNST & YOUNG LLP
Vienna, Virginia
August 23, 1999, except for Note 2, as
to which the date is October 13, 1999
F-8
<PAGE> 87
APPALACHIAN NATURAL GAS TRUST
STATEMENT OF ASSETS AND TRUST CORPUS
AS OF AUGUST 19, 1999
<TABLE>
<S> <C>
Cash........................................................ $1,000
======
Trust Corpus................................................ $1,000
======
</TABLE>
See Accompanying Notes to Statement of Assets and Trust Corpus.
F-9
<PAGE> 88
APPALACHIAN NATURAL GAS TRUST
NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS
1. TRUST ORGANIZATION
Appalachian Natural Gas Trust, formerly the Appalachian Basin Royalty Trust
(the "Trust"), is a grantor trust that was created on August 18, 1999 by Eastern
States Oil & Gas, Inc. (the "Company"), a wholly owned subsidiary of Statoil
Energy Holdings, Inc. The Statement of Assets and Trust Corpus reflects the
Company's initial cash contribution to the Trust of $1,000.
The Trust was formed to hold net profits interests entitling it to 80% of
the net proceeds received by the Company from the sale of oil and natural gas
from 2,471 producing wells in Kentucky and West Virginia and 10% of the net
proceeds received by the Company from the sale of oil and natural gas in certain
undeveloped properties in Kentucky and West Virginia (the "Underlying
Properties"). These net profits interests will be conveyed to the Trust by the
Company upon completion of a successful public offering of beneficial interests
("Units") in the Trust.
The Trust will terminate upon the first occurrence of: (a) disposition of
all net profits interests pursuant to terms of the Trust Agreement, (b) when net
proceeds attributable to the Underlying Properties are less than $3.5 million
per year for each of two successive years after the year 2000 in the state of
West Virginia or less than $3.5 million per year for each of two successive
years after the year 2000 in the state of Kentucky, or (c) a vote of at least
66 2/3% of the Trust Unitholders to terminate the Trust in accordance with
provisions of the Trust Agreement. These termination clauses will be finalized
upon execution of the Trust Conveyance Agreement.
2. SUBSEQUENT EVENT
On October 13, 1999, The Statoil Group -- Norway ("Statoil") announced
plans to seek a buyer for its U.S. natural gas and electric power production and
marketing unit, Statoil Energy, Inc. ("STEN") in connection with a corporate
restructuring process. The Statoil Group has announced its intentions to market
STEN as an integrated enterprise consisting of STEN's subsidiaries, including
Eastern States, involved in gas production, power production, energy marketing
and energy trading. However, the Statoil Group may determine that the sale of
individual assets or divisions, including Eastern States, is more appropriate.
If such a sale of Statoil Energy or Eastern States occurs, the Company cannot
assure that it will not adversely affect Eastern States.
F-10
<PAGE> 89
APPALACHIAN NATURAL GAS TRUST
UNAUDITED PRO FORMA STATEMENT OF ASSETS
AND TRUST CORPUS AS OF SEPTEMBER 1, 1999
(IN THOUSANDS)
<TABLE>
<S> <C>
Cash...................................................... $ 1
Oil and Gas Property...................................... 210,000
--------
$210,001
========
Trust Corpus.............................................. $210,001
========
</TABLE>
NOTE -- BASIS OF PRESENTATION
Appalachian Natural Gas Trust (the "Trust"), formerly the Appalachian Basin
Royalty Trust, is a grantor trust that was created on August 18, 1999 by Eastern
States Oil & Gas, Inc. (the "Company"), a wholly owned subsidiary of Statoil
Energy Holdings, Inc. The Statement of Assets and Trust Corpus reflects the
Company's initial cash contribution to the Trust of $1,000.
The Trust was formed to hold net profits interests entitling it to 80% of
the net proceeds received by the Company from the sale of oil and natural gas
from 2,471 producing wells in Kentucky and West Virginia and 10% of the net
proceeds received by the Company from the sale of oil and natural gas in certain
undeveloped properties in Kentucky and West Virginia (the "Underlying
Properties"). These net profits interests will be conveyed to the Trust by the
Company upon completion of a successful public offering of beneficial interests
("Units") in the Trust. The pro forma Statement of Assets and Trust Corpus
reflects the sale of 10.5 million Units at $20 per Unit, which includes units
retained by the Company.
F-11
<PAGE> 90
APPALACHIAN NATURAL GAS TRUST
UNAUDITED PRO FORMA STATEMENT OF DISTRIBUTABLE CASH
FOR THE YEAR ENDED DECEMBER 31, 1998 AND
FOR THE EIGHT MONTHS ENDED AUGUST 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
EIGHT MONTHS
YEAR ENDED ENDED
DECEMBER 31, AUGUST 31,
1998 1999
------------ ----------------
<S> <C> <C>
Revenue:
Gas sales................................................. $41,835 $25,594
Oil sales................................................. 242 230
------- -------
Total revenues.................................... 42,077 25,824
------- -------
Direct Operating Expenses:
Taxes on production and property.......................... 3,809 2,338
Production expenses....................................... 3,603 2,401
------- -------
Total expenses.................................... 7,412 4,739
------- -------
Excess of Revenues over Direct Operating Expenses........... 34,665 21,085
------- -------
Pro Forma Adjustments (Note 2):
Revenue................................................... (2,439) (1,533)
Production expenses....................................... (897) (599)
Overhead.................................................. (1,870) (1,250)
------- -------
Total pro forma adjustments....................... (5,206) (3,382)
------- -------
Pro Forma Net Proceeds(1)................................... 29,459 17,703
Net Profits Interests Percentage............................ 80% 80%
------- -------
Trust Cash.................................................. 23,567 14,162
Less Trust General and Administrative Expenses.............. (300) (200)
------- -------
Distributable Cash.......................................... $23,267 $13,962
======= =======
</TABLE>
- ---------------
(1) There were no development costs for the period January 1, 1998 through
August 31, 1999, since all wells drilled by the Company during that period
were excluded from the Underlying Properties. The Company expects to incur
development costs averaging approximately $4.4 million per year, net to the
Trust, for at least the next five years, which will reduce distributable
cash by a corresponding amount per Unit.
See Accompanying Notes to Pro Forma Statement of Distributable Cash.
F-12
<PAGE> 91
APPALACHIAN NATURAL GAS TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE CASH
(UNAUDITED)
1. BASIS OF PRESENTATION
Appalachian Natural Gas Trust (the "Trust") was created in August 1999 by
Eastern States Oil & Gas, Inc. (the "Company"). The Company will convey certain
net profits interests (the "Net Profits Interests") from the Underlying
Properties to the Trust in exchange for all of the units of beneficial interest
in the Trust.
The pro forma statement of distributable cash of the Trust for the year
ended December 31, 1998 and eight months ended August 31, 1999 has been prepared
from the historical statement of revenues and direct operating expenses of the
Underlying Properties, adjusted, and based on the following assumptions:
a.The Trust was formed and the Net Profits Interests were conveyed to the
Trust prior to January 1, 1998.
b.Distributable cash of the trust is calculated based on the gross proceeds
from the Underlying Wells. For the period presented there is no pro forma
distributable cash attributable to the 10% net profits interest since all
wells drilled by Eastern States during this time period are excluded from
the Underlying Properties. Net Proceeds is a defined term in the Net
Profits Interests conveyances to the Trust.
c.Administrative expense is estimated to be $300,000 annually. Such expense
generally would include Trustee fees and costs incurred by the Trustee to
administer the Trust and report Trust results to Unitholders, including
the expense of attorneys, independent auditors, reservoir engineers,
printing and mailing.
2. PRO FORMA ADJUSTMENTS
The following pro forma adjustments were made to the historical revenues
and direct operating expenses of the Underlying Properties to present Trust pro
forma distributable cash for the year ended December 31, 1998 and eight months
ending August 31, 1999:
a.The Net Profits Interest conveyances to the Trust provide for the Company
to receive gathering and compression fees which cover actual costs
incurred plus depreciation and to provide a return on invested capital.
The adjustment to record depreciation and return on invested capital is
reflected as a reduction to revenue in the pro forma statement.
b.The conveyances to the Trust will provide for the Company to charge
production expenses at fixed rates, subject to adjustment, which exceed
actual costs incurred by the Company. Such additional charges are shown
as an increase in production expenses in the pro forma statement.
c.A Company overhead charge of $1,870,000 and $1,250,000 for the year ended
December 31, 1998 and eight months ended August 31, 1999, respectively,
were deducted. The overhead charge is based on a monthly count of active
wells operated by the Company and is specified by the terms of the Net
Profits Interests conveyances to the Trust.
3. FEDERAL INCOME TAXES
As a grantor trust, the Trust will not be required to pay federal income
taxes. Accordingly, the accompanying pro forma statement of distributable income
does not include a provision for federal income taxes.
F-13
<PAGE> 92
APPALACHIAN NATURAL GAS TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE CASH -- (CONTINUED)
(UNAUDITED)
4. CONTINGENCIES
The Company is involved in various legal actions and claims arising in the
normal course of business. Based upon its current assessment of the facts and
the law, management does not believe that the outcome of any such action or
claim will have a material adverse effect upon the value of the underlying
properties. However, these actions against the Company are subject to the
uncertainties inherent in any litigation.
5. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Proved oil and natural gas reserves of the Trust have been estimated as of
August 31, 1999 by Ryder Scott Company, L.P., independent petroleum engineers.
In accordance with Statement of Financial Accounting Standards No. 69, estimates
of future net revenues from proved reserves have been prepared using year-end
oil and natural gas prices and current costs to produce and develop the proved
reserves. The standardized measure of future net cash flows from oil and natural
gas reserves is calculated based on discounting such future net cash flows at an
annual rate of 10%. Crude oil prices were $18.75 per barrel at August 31, 1999.
The weighted average spot gas price was $2.61 per Mcf at August 31, 1999. Since
the Trust is not subject to taxation at the trust level, no provision is
included for federal income taxes.
Reserve quantities and revenues for the Net Profits Interests were
estimated from projections of reserves and revenues attributable to the
Underlying Properties. Since the Trust has a defined Net Profits Interest, the
Trust does not own a specific ownership percentage of the oil and natural gas
reserves or production quantities. Accordingly, reserves and production
allocated to the Trust pertaining to its interests in 80% of the net cash
proceeds from the underlying wells and 10% of the net cash proceeds from the
undeveloped properties have effectively been reduced to reflect recovery of the
Trust's 80% and 10% portion, respectively, of applicable production and
development costs, excluding overhead and trust administrative expenses. Because
Trust reserve quantities are determined using an allocation formula, any
fluctuations in actual or assumed prices or costs will result in revisions to
the estimated reserve quantities allocated to the Net Profits Interests.
The Net Profits Interests' share of production and development costs have
been deducted in calculating distributable cash attributable to the Net Profits
Interests. Accordingly, these costs are not shown separately as future costs in
calculating the standardized measure. Only production taxes, calculated at the
same rate as incurred on the Underlying Properties, is included in future
production costs in calculating the standardized measure.
The standardized measure of future net cash flows is not intended to
represent the fair value of the Trust. Numerous uncertainties are inherent in
estimating volumes and values of proved reserves and in projecting future
production rates and timing of development expenditures. Such reserve estimates
are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production may be substantially different
from the original estimates. Also, because natural gas prices are influenced by
seasonal demand, use of year-end prices, as required by the Financial Accounting
Standards Board, may not be representative in estimating future revenues or
reserve data.
<TABLE>
<CAPTION>
NATURAL GAS (MCF) OIL (BBLS)
----------------- ----------
(IN THOUSANDS)
<S> <C> <C>
PROVED RESERVES
Balance, August 31, 1999.................................... 239,101 171
PROVED DEVELOPED RESERVES
August 31, 1999............................................. 210,018 171
</TABLE>
F-14
<PAGE> 93
APPALACHIAN NATURAL GAS TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE CASH -- CONTINUED
(UNAUDITED)
5. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED RESERVES AT AUGUST 31, 1999
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
Future cash inflows......................................... $ 628,249
Future production taxes and development..................... (51,042)
---------
Future net cash flows....................................... 577,207
10% discount factor......................................... (376,787)
---------
Standardized measure of discounted future net cash flows.... $ 200,420
=========
</TABLE>
F-15
<PAGE> 94
APPENDIX A
INFORMATION ABOUT
EASTERN STATES OIL & GAS, INC.
THE TRUST UNITS ARE NOT INTERESTS IN OR OBLIGATIONS OF
EASTERN STATES OIL & GAS, INC.
<PAGE> 95
EASTERN STATES OIL & GAS, INC.
Eastern States Oil & Gas, Inc. is an independent energy company engaged in
the development, production, acquisition, marketing, gathering and
transportation of natural gas and oil in the Appalachian Basin. Eastern States
is the largest owner of proved natural gas reserves in the Appalachian Basin.
Substantially all of our natural gas and oil reserves are located in Kentucky,
Ohio and West Virginia. We also have properties in Indiana, Maryland, Michigan
and Virginia.
Since its inception in 1994, Eastern States has grown through developmental
drilling and acquisitions of natural gas and oil producing properties. During
this period, we spent approximately $650 million on 16 acquisitions, including
the acquisition of Blazer Energy Corp., formerly Ashland Exploration, Inc., in
July 1997. The acquisition of Blazer Energy increased our estimated proved
reserves in the Appalachian Basin by approximately 769 Bcfe. Eastern States and
Blazer have since combined their assets in the Appalachian Basin.
For the years ended December 31, 1996, 1997 and 1998, Eastern States had
total revenue of $18.2 million, $65.4 million and $104.7 million, and for the
first six months of 1999, we had total revenues of $57.7 million. For the years
ended December 31, 1996, 1997 and 1998, Eastern States had net income of $3.9
million, $9.2 million and $8.3 million, and for the first six months of 1999, we
had net income of $6.0 million.
Eastern States currently owns and operates over 5,700 gross wells in the
Appalachian Basin. At December 31, 1998, Eastern States' estimated net proved
reserves were 1,062 Bcfe, of which 709 Bcfe, or 67%, were proved developed. The
estimated discounted future net cash flows of Eastern States' proved reserves,
before United States income taxes, were $675 million as of December 31, 1998.
For the six months ended June 30, 1999, total average net sales meter natural
gas and oil production was 104 MMcfe per day, of which 98% was natural gas.
Eastern States is continually evaluating oil and natural gas properties and
other investment opportunities in addition to its development and operation of
existing properties, including the underlying properties.
Eastern States is an indirect wholly owned subsidiary of Statoil Energy,
Inc. Statoil Energy also:
- owns and operates power plants throughout the northeast and the
mid-Atlantic region;
- is a leading trader of wholesale electricity and natural gas;
- specializes in providing a broad range of energy and risk management
services involving the delivery of natural gas, electricity and
alternative fuels to large industrial, institutional and commercial
customers; and
- through its indirect wholly owned subsidiary, Eastern States Exploration
Company, owns and operates approximately 600 wells in Pennsylvania, with
estimated net proved reserves of 39 Bcfe at December 31, 1998 and an
average daily net sales meter production of 6 MMcfe for the six months
ended June 30, 1999. Eastern States does not own any interest in Eastern
States Exploration Company.
Statoil Energy is currently an indirect wholly owned U.S. subsidiary of the
Norwegian state oil company "den norske stats oljeselskap a.s" which is also
known as The Statoil Group. The Statoil Group has substantial ongoing
commitments associated with various development projects worldwide and has
numerous international investment opportunities competing for limited capital.
Based upon those capital commitments, various assets and interests, including
Statoil Energy, were evaluated for strategic ranking, possible sale or joint
venture. Based upon that evaluation, The Statoil Group concluded that it was
unable to continue to fund Statoil Energy's planned increase of the scale of its
operations and targeted it for a possible joint venture.
A-1
<PAGE> 96
The Statoil Group retained an investment banking firm, Credit Suisse First
Boston, early in 1999 to implement The Statoil Group's strategy with respect to
Statoil Energy. These activities initially focused on a search for a 50%
strategic partner to obtain and combine complementary assets and activities to
pursue business opportunities in the sector of the U.S. energy market not
regulated by the FERC. Based upon the results of its efforts to pursue this
joint venture strategy, The Statoil Group and its financial advisor concluded
that prospective partners, primarily utility companies, were not interested in
sharing the corporate governance and capital requirements of Statoil Energy. As
a result, on October 13, 1999 The Statoil Group announced that it plans to sell
its equity ownership in Statoil Energy and has initiated discussions with
several companies in that regard.
None of The Statoil Group, Statoil Energy or Eastern States can provide
assurance that such a sale will be made or when such a sale might be concluded.
While The Statoil Group is currently exploring the possible sale of Statoil
Energy and its subsidiaries, including Eastern States, The Statoil Group may
determine that the sale of individual assets or divisions, including Eastern
States, is more appropriate. If a sale of Statoil Energy or Eastern States is
made, there is no assurance that it would not adversely affect Eastern States.
However, any successor to Eastern States would be subject to the obligations of
Eastern States under the transfer documents and the Trust Agreement described in
the main part of this prospectus.
BY PURCHASING TRUST UNITS YOU WILL NOT ACQUIRE AN OWNERSHIP INTEREST IN ANY
OF EASTERN STATES, STATOIL ENERGY OR THE STATOIL GROUP.
Eastern States is a Delaware corporation. Its principal executive offices
are located at 2800 Eisenhower Avenue, Alexandria, Virginia 22314 and the
telephone number is (703) 317-2300.
RISK FACTORS APPLICABLE TO EASTERN STATES
NATURAL GAS PRICE DECLINES AND MARKET VOLATILITY COULD ADVERSELY AFFECT OUR
FINANCIAL RESULTS.
Even relatively modest changes in natural gas prices may significantly
change our revenues, results of operations, cash flows and value of proved
reserves. The markets for natural gas have been volatile and are likely to
continue to be volatile in the future. Natural gas prices can fluctuate widely
in response to relatively minor changes in the supply of and demand for natural
gas, market uncertainty and a variety of additional factors that are beyond our
control, such as:
- weather conditions, primarily in the northeast United States;
- the supply and price of domestic and foreign natural gas and oil;
- delivery interruptions by upstream pipeline companies;
- the level of demand;
- worldwide economic and political conditions;
- the price and availability of alternative fuels;
- environmental regulations; and
- worldwide energy conservation measures.
Moreover, government regulations, such as regulation of natural gas
transportation or price controls, if imposed, could affect product prices in the
long term.
Natural gas produced in the Appalachian Basin has historically received a
premium over natural gas produced in other regions due to the region's close
proximity to the markets in the northeast United
A-2
<PAGE> 97
States. For the period 1991 through 1998, natural gas price indices for
Appalachian Basin production have averaged $0.25 per MMbtu more than prices for
natural gas contracts traded on the NYMEX for the delivery of natural gas at
Henry Hub, Louisiana. During these eight years, the average annual Appalachian
Basin premium has ranged from $0.14 per MMbtu to $0.47 per MMbtu. Any material
decrease in this average premium could have an adverse impact on the proceeds
received from the sale of natural gas by Eastern States.
WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FINANCING TO EXECUTE OUR OPERATING
STRATEGY.
Our business is capital intensive and, to maintain our base of proved gas
reserves, a significant amount of cash flow from operations must be invested in
development activities. We make substantial capital expenditures for the
development, acquisition and production of natural gas reserves. Historically,
we have financed these expenditures primarily from the following sources:
- cash generated by operations;
- bank borrowings; and
- loans and capital contributions from The Statoil Group.
Our management believes that we will have sufficient cash generated from
operations to fund planned capital expenditures through at least the year 2000.
If our revenues significantly decrease as a result of lower natural gas prices,
operating difficulties or declines in reserves, we may not be able to expend the
capital necessary to undertake or complete future development programs or
acquisition opportunities. Without these timely investments, our gas production
and reserves will decline.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS.
Our outstanding indebtedness under the promissory note with Statoil Energy
Holdings, Inc., an indirect subsidiary of the Statoil Group, was $505 million at
September 30, 1999 and matures on December 31, 2001. Our intercompany
indebtedness with affiliates of Statoil Energy at September 30, 1999 was
approximately $51 million. Our ability to meet our debt service obligations and
reduce our total indebtedness will depend on our future performance. Our future
performance, in turn, depends on many factors that are beyond our control such
as general economic, financial and business conditions. We cannot assure you
that economic conditions and financial, business and other factors will not
adversely affect our future performance.
ESTIMATES OF NATURAL GAS RESERVES ARE UNCERTAIN.
The calculations of proved reserves of natural gas and oil included in this
appendix are only estimates. These estimates were prepared by Eastern States and
reviewed by Ryder Scott Company, L.P., independent petroleum engineers. The
accuracy of any reserve estimate is a function of the quality of available data,
engineering and geological interpretation and judgment, and the assumptions used
regarding quantities of recoverable natural gas and natural gas prices. Actual
prices, production, development expenditures, operating expenses and quantities
of recoverable oil and natural gas reserves will vary from those we assume in
our estimates, and those variances may be significant. Any significant variance
from the assumptions used could result in the actual quantity of our reserves
and future net cash flow being materially different from the estimates in our
review reports. In addition, results of drilling, testing and production and
changes in crude oil, natural gas liquids and natural gas prices after the date
of the estimate may result in substantial upward or downward revisions.
A-3
<PAGE> 98
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.
Without successful exploration, development or acquisition activities, our
reserves and revenues will decline over time. The continuing development of
reserves, acquisition activities and, to a lesser extent, exploration, will
require significant expenditures. If our cash flow from operations is not
sufficient for this purpose, we may not be able to obtain the necessary funds
from other sources.
WE MAY NOT BE SUCCESSFUL IN DRILLING NEW WELLS.
We currently anticipate drilling an average of approximately 200 to 230 new
wells per year in Kentucky and West Virginia for at least the next five years.
We cannot assure you that any of the new wells will be successful or produce in
commercial quantities or that we will be able to drill approximately 200 to 230
new wells per year.
FACILITIES MAINTENANCE ON THIRD PARTY PIPELINE DELIVERY SYSTEMS COULD CREATE
INTERRUPTIONS IN THE DELIVERY OF NATURAL GAS WE PRODUCE.
We depend on the availability of third party pipeline delivery systems to
transport over 90% of our natural gas. Any interruptions in the availability of
these systems due to facilities maintenance requirements or other extraordinary
events could inhibit our ability to sell our natural gas. For example, Columbia
Transmission Corp. has shut down one of its pipelines in Kentucky from September
27, 1999 to November 15, 1999 for replacement of a portion of its pipeline
system. This temporary shut-down will delay the delivery and sale of
approximately 30% of Eastern States' natural gas production in Kentucky.
WE MAY NOT INSURE AGAINST ALL HAZARD LOSSES.
We insure against some, but not all, of the hazards associated with the
natural gas industry. For example, we are not insured against the following
hazards:
- fines and penalties;
- pollution events occurring prior to Eastern States' acquisition date;
- professional errors and omissions of engineers, geologists and surveyors;
- loss or unrecoverability of oil and natural gas reserves;
- loss of downhole equipment;
- loss of income due to third party failure to provide equipment or
materials; and
- war and associated events of civil unrest.
As a result, we may be exposed to liability or losses that could be substantial
due to events that we do not insure.
HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.
In order to manage our exposure to price risks in the marketing of our gas,
we enter into hedging arrangements relating to a portion of our expected
production. In the past, these hedges have involved a number of arrangements at
a variety of fixed prices and other provisions, including price floors and
ceilings. In the future, we may enter into natural gas futures contracts,
options, collars and swaps. Our hedging activities are subject to a number of
risks, including instances in which:
- production is less than expected;
- there is a widening of price differentials between delivery points
required by fixed price delivery contracts to the extent they differ from
those on our production; or
- counterparties to our futures contract are unable to meet the financial
terms of the transaction.
While hedging arrangements limit the risk of declines in natural gas
prices, they may also limit the extent to which we benefit from increases in the
price of natural gas.
A-4
<PAGE> 99
WE MAY INCUR SUBSTANTIAL COSTS TO COMPLY WITH ENVIRONMENTAL AND OTHER
GOVERNMENTAL REGULATIONS.
Environmental and other governmental regulations have increased the costs
to plan, design, drill, install, operate and abandon oil and natural gas wells
and other facilities. Increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from our operations, could result in
substantial costs and liabilities in the future.
FORWARD-LOOKING STATEMENTS
This appendix contains forward-looking statements relating to Eastern
States' operations and the oil and gas industry. Such forward-looking statements
are based on management's current projections and estimates and are identified
by words such as "expects," "intends," "plans," "projects," "anticipates,"
"believes," "estimates" and similar words. These statements are not guarantees
of future performance and involve risks, uncertainties and assumptions that are
difficult to predict. Therefore, actual results may differ materially from what
is expressed or forecasted in such forward-looking statements.
Among the factors that could cause actual results to differ materially are:
- natural gas and oil price fluctuations;
- the availability of funds for our future development programs and
acquisitions;
- the results of our development program;
- potential delays or failure to achieve expected production from existing
and future exploitation and development projects;
- potential disruption of operations because of our failure or the failure
of others with whom we have material relationships to achieve timely Year
2000 compliance; and
- potential liability resulting from pending or future litigation.
In addition, these forward-looking statements may be affected by general
domestic and international economic and political conditions.
BUSINESS AND PROPERTIES
HISTORICAL DEVELOPMENT OF OUR BUSINESS
Eastern States was organized in April 1994 to engage in the acquisition,
exploration and development of natural gas, oil and other mineral interests.
Eastern States has developed a significant reserve base, primarily through:
- acquisitions of proved natural gas and oil reserves and undeveloped
leaseholds;
- strategic acquisitions of other companies engaged in the development and
production of natural gas and oil; and
A-5
<PAGE> 100
- development and exploitation of these leaseholds and acquired properties
through drilling, recompletions of existing wells and construction of
pipelines and compression projects.
Our estimated net proved reserves increased from 38 Bcfe at December 31,
1994 to 1,062 Bcfe at December 31, 1998. Our average daily production increased
from 2 MMcfe per day at December 31, 1994 to over 100 MMcfe per day at December
31, 1998. Our acquisitions have added a total of approximately 900 Bcfe to our
reserve base. Additionally, we have expended a total of $81 million to drill 418
net wells during the last five years, developing approximately 114 Bcfe of net
proved developed reserves. Approximately 97% of our wells drilled during this
five-year period were completed as producing wells. The direct finding costs for
our drilling program averaged $0.71 per Mcfe during the same period.
Acquisitions. Since our formation, we have made a series of acquisitions of
natural gas and oil producing properties, including the following:
- In August 1994, we acquired natural gas and oil properties, including
gathering lines, in West Virginia and Kentucky from Southeastern Gas
Company for approximately $17 million in cash.
- In April 1996, we acquired natural gas and oil properties, including
gathering lines, in West Virginia from CNG Transmission Company for
approximately $16 million in cash.
- In May 1996, we acquired natural gas and oil properties, including
gathering lines, in Ohio from General Motors Corporation for
approximately $34 million in cash.
- In July 1997, we acquired Blazer Energy for approximately $567 million in
cash. Immediately thereafter, we sold Blazer Energy's Gulf of Mexico
properties to our affiliate Statoil Exploration U.S., Inc., an indirect
wholly owned subsidiary of The Statoil Group, for approximately $82
million. In 1998, we sold a portion of Blazer Energy's proved developed
reserves, along with undeveloped acreage, located outside the Appalachian
Basin to Whiting Petroleum Corporation and BWAB Incorporated for
approximately $24 million.
Appalachian Natural Gas Trust. In August 1999, Eastern States formed the
Appalachian Natural Gas Trust, which will hold net profits interests in the
Appalachian Basin area of Kentucky and West Virginia. The net profits interests
will entitle the trust to receive:
- 80% of the net proceeds received by Eastern States from the sale of
natural gas from 2,471 producing wells owned by Eastern States in
Kentucky and West Virginia; and
- 10% of the net proceeds received by Eastern States from the sale of
natural gas from all wells drilled after September 1, 1999 in the leases
in Kentucky and West Virginia that are subject to the net profits
interests.
The net profits interests to be contributed to the trust contain
approximately 240 Bcfe of proved reserves.
Eastern States will receive all of the net cash proceeds from the sale of
trust units in an underwritten public offering, which proceeds are currently
estimated to be approximately $146.5 million before expenses of the offering,
assuming the underwriters do not exercise their over-allotment option. We intend
to use the net proceeds of the offering to repay a portion of the existing
indebtedness to Statoil Energy Holdings.
OUR BUSINESS STRATEGY
Our business strategy is to increase cash flow by increasing both our
reserves and production through:
- the development and exploitation of existing properties; and
- the selective acquisition of additional properties with development and
exploitation potential.
A-6
<PAGE> 101
Enhancing Our Appalachian Basin Position
We are continuing to develop our large leasehold position in the
Appalachian Basin, where we own approximately 1.4 million gross acres and 1,158
proved undeveloped drilling locations at December 31, 1998. We currently expect
to drill 200 to 230 wells per year for at least the next five years, which is
expected to require approximately $44 million to $50 million per year in capital
spending. Our level of capital expenditures may vary in the future depending on
a number of factors, including energy market conditions, availability and
reliability of supplies of goods and services and costs in comparison to
expected rates of return.
Pursuing Growth Through Targeted Acquisitions
We are continually evaluating opportunities to acquire producing and
undeveloped properties that possess, among others, one or more of the following
characteristics:
- close proximity to our existing operations;
- potential opportunities to increase reserves through production
enhancement of existing reserves and the discovery of reserves on
undeveloped properties; and
- potential opportunities to reduce production expenses through more
efficient operations.
Our multi-disciplined due diligence teams have evaluated approximately 100
acquisition opportunities during the past five years. These same teams have also
been directly involved in the assimilation, exploration and development of
acquired properties. We believe this continuity and focus as well as our
established operating presence will enhance our competitive ability to complete
future acquisitions.
PROPERTIES AND DEVELOPMENT ACTIVITIES
At December 31, 1998, we estimated our total estimated net proved reserves
at 1,062 Bcfe. Estimated net proved developed reserves were 709 Bcfe,
representing 67% of our total net proved reserves. Except for one producing well
located in the Michigan Basin, all of our estimated net proved reserves are
located in the Appalachian Basin. All information in this appendix relating to
estimated natural gas and oil reserves and the estimated future net cash flows
before taxes attributable to those reserves is based on estimates prepared by us
that have been reviewed by Ryder Scott Company, L.P., independent petroleum
engineers. Under a review report, the independent petroleum engineers review
estimates prepared by a company's engineering staff. The following table
summarizes our estimated net proved reserves as of December 31, 1998, in each
state in which we own proved reserves, based on the standardized measure before
United States income taxes as of December 31, 1998. The standardized measure
does not include the value of Section 29 tax credits attributable to Devonian
Shale and tight sands natural gas properties and future plugging and abandonment
liabilities. See "-- Section 29 Tax Credits."
<TABLE>
<CAPTION>
DECEMBER 31, 1998 PROVED RESERVES
------------------------------------------------------------------
NATURAL % OF TOTAL
GAS TOTAL STANDARDIZED STANDARDIZED
STATE (MMCF) OIL (MBBLS) (MMCFE) MEASURE MEASURE
- ----- --------- ----------- --------- ------------- ------------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
West Virginia.................... 583,037 345 585,112 $364 54%
Kentucky......................... 394,812 62 395,184 258 38%
Ohio............................. 57,933 1,585 67,440 41 6%
Other including proved reserves
located in Maryland, Michigan
and Virginia................... 13,932 12 14,002 12 2%
--------- ----- --------- ---- ---
Total.................. 1,049,714 2,004 1,061,738 $675 100%
</TABLE>
A-7
<PAGE> 102
At December 31, 1998, we had identified 1,158 additional proved undeveloped
drilling locations, many of which will be drilled as part of our planned
drilling programs over the next five years. For the period January 1, 1998 to
June 30, 1999, approximately 40% of all wells drilled by Eastern States were on
locations classified as unproved at the time of drilling. Our total net gas
production from the Appalachian Basin in 1998 averaged approximately 100 MMcf
per day, with minimal associated oil or water production. We have an average
working interest of approximately 94% in our wells in the Appalachian region,
which represents an approximately 84% average net revenue interest.
Natural gas produced in the Appalachian Basin has historically received a
premium over natural gas produced in other regions due to the region's close
proximity to the major gas consuming markets in the northeastern United States.
For the period 1991 through 1998, wellhead natural gas prices in the Appalachian
Basin have averaged on an annual basis $0.25 per MMbtu more than the Henry Hub
and NYMEX wellhead natural gas prices. During these eight years, the average
annual Appalachian Basin premium has ranged from $0.14 per MMbtu to $0.47 per
MMbtu. In addition, natural gas produced by Eastern States also typically
receives an "energy content" premium since it contains an average of 1,116 Btu
per cubic foot as compared to NYMEX prices which are quoted based on 1,000 Btu
per cubic foot. The Appalachian Basin premium is typically lower during
warmer-than-normal winters, such as the previous two winters.
Eastern States will transfer to the trust, effective as of September 1,
1999:
- an 80% net profits interest in 2,471 producing natural gas wells in
Kentucky and West Virginia; and
- a 10% net profits interest in substantially all of its current oil and
gas leasehold interests in Kentucky and West Virginia.
Eastern States will retain the following:
- rights to the Rome exploration area in Kentucky and West Virginia;
- leases farmed out to third parties;
- leases with known transfer or title issues, including all potential
coalbed methane exploration and development rights;
- Section 29 credit wells;
- wells drilled during the 20 months ended August 31, 1999;
- wells with title issues;
- wells with high operating costs;
- marginal producing wells; and
- wells in which Eastern States is not the operator.
The Appalachian Basin is the oldest and geographically one of the largest
natural gas producing regions in the United States. As of June 30, we operated
over 5,700 gross, or 5,400 net, wells, 3,500 miles of gathering pipelines and
104 compressor stations in 47 counties in five states in the region. Our wells
in the Appalachian Basin produce from geologic formations that are Pennsylvanian
to Cambrian in age. Our wells range from 1,000 to 8,000 feet, with an average
depth of approximately 5,000 feet. Individual wells often have economic lives of
up to 50 years. The costs to develop Appalachian Basin reserves are low compared
to other regions of the United States because of the relatively shallow
reservoir depths and the low incidence of dry holes. Over the past five calendar
years, we have drilled 418 net wells in the Appalachian region, with a 97%
completion rate.
Our wells in the Appalachian Basin are characterized by a relatively high
reserve-to-production ratio of over 27 years and a low natural production
decline rate averaging 7% to 8% for the first five years. Reserves in the
Appalachian Basin have a high degree of development success, that is, as
development
A-8
<PAGE> 103
progresses reserves are reclassified from the unproved to the proved category
and additional layers of offset reserves are added as proved undeveloped
reserves.
We believe that we realize operational efficiencies and therefore are able
to maximize the return on our investment in the Appalachian Basin because of:
- our large acreage position;
- our substantial ongoing development program conducted over a number of
years and the experience and expertise gained from these activities; and
- our extensive gas gathering system.
Our Appalachian gas gathering system is interconnected with various
intrastate and interstate transmission lines that allow access to both local and
major markets in the northeastern United States. Some of our Appalachian natural
gas production is connected directly to end users through our pipelines. We have
acquired and are continuing to seek acquisitions of gathering facilities from
transmission companies to allow for direct connection to transmission pipelines.
Our gas gathering system is also used to carry third party natural gas to market
through purchase/resale or transport arrangements.
The principal Appalachian Basin properties are as follows:
Pikeville Area, Kentucky
The Pikeville Area includes approximately 37% of Eastern States' total net
proved reserves. Eastern States' interests in this area are concentrated in
Pike, Knott, Floyd, Breathitt, Morgan, Elliott and Carter counties, Kentucky on
approximately 352,000 gross acres, which includes the Rome area. We produce
natural gas predominantly from the Maxton, Big Lime and Berea and Devonian Shale
formations at depths ranging from 1,000 to 8,000 feet. Sales meter production
attributable to Eastern States' net interest averaged 32 MMcfe per day during
the first two quarters of 1999. Eastern States drilled 46 gross development
wells and three gross exploratory wells in this area during fiscal 1998 with 45
of the development wells and one of the exploratory wells currently producing at
a combined rate of approximately 4.0 MMcf per day. In the six month period ended
June 30, 1999, Eastern States drilled and completed 24 wells. We had 461 proved
undeveloped locations identified for drilling as of December 31, 1998.
Brenton Area, West Virginia
The Brenton Area includes approximately 30% of Eastern States' total net
proved reserves. Eastern States' interests are located mainly in Logan, Mingo,
McDowell and Wyoming counties in southern West Virginia on approximately 397,000
gross acres. We produce natural gas predominantly from the Ravencliff, Maxton,
Big Lime and Berea and Devonian Shale formations at depths ranging from 2,000 to
7,000 feet. Sales meter production attributable to Eastern States' net interest
averaged 28 MMcfe per day for the first two quarters of 1999. Eastern States
drilled and completed 57 gross wells in the area during 1998, which are
currently producing at a combined rate of approximately 6.5 MMcf per day. In the
six month period ended June 30, 1999, Eastern States drilled and completed 18
wells. We had 429 proved undeveloped locations identified for drilling as of
December 31, 1998.
Madison Area, Eastern West Virginia
The Madison Area includes approximately 17% of Eastern States' total net
proved reserves. Eastern States' interests are located in Lincoln, Kanawha,
Boone, Raleigh, Fayette, Nicholas and Clay counties in South-Central West
Virginia on approximately 374,000 gross acres. We produce natural gas
predominantly from the Maxton, Big Lime, Big Injun, Weir, Berea and Devonian
Shale formations at depths ranging from 1,700 to 6,000 feet. Sales meter
production attributable to Eastern States' net interest averaged 18 MMcfe per
day for the first two quarters of 1999. Eastern States drilled and completed 50
gross wells during 1998, all of which are currently producing at a combined rate
of approximately 4.3 MMcf per day. In the six month period ended June 30, 1999,
Eastern States drilled and completed 21 wells. We had 208 proved undeveloped
locations identified for drilling as of December 31, 1998.
A-9
<PAGE> 104
Weston Area, West Virginia
The Weston Area includes approximately 9% of Eastern States' total net
proved reserves. Eastern States' interests are located largely in Jackson,
Gilmer, Doddridge, Roane, Calhoun, Harrison and Wetzel counties in northern West
Virginia on approximately 192,000 gross acres. We produce natural gas from Upper
Devonian sandstone formations at depths ranging from 1,800 to 5,000 feet. Sales
meter production attributable to our net interest averaged 15 MMcfe per day for
the first two quarters of 1999. We drilled and completed 11 gross wells during
1998, all of which are producing at a combined rate of approximately 0.8 MMcf
per day. We had 20 proved undeveloped locations identified for drilling as of
December 31, 1998.
Noble/Cambridge Area, Ohio
The Noble/Cambridge Area includes approximately 6% of Eastern States' total
net proved reserves. Eastern States' interests are located largely in Trumbull,
Mahoning, Portage, Coshocton, Licking, Noble and Monroe counties in eastern Ohio
on approximately 87,000 gross acres. We produce natural gas predominately from
the Silurian Clinton sandstone at depths ranging from 3,500 to 6,000 feet.
Additionally, natural gas and minor amounts of oil are produced from the
Cambro-Ordovician Knox Group at depths approximating 7,000 feet, and
Mississippian and Devonian sandstones at depths of 2,000 to 3,000 feet. Sales
meter production attributable to our net interest averaged 10 MMcfe per day for
the first two quarters of 1999. Eastern States drilled and completed 11 gross
wells during 1998. Of these, nine gross wells are producing at a combined rate
of approximately 0.4 MMcfe per day. We had 40 proved undeveloped locations
identified for drilling as of December 31, 1998.
Additional Properties
Eastern States also owns additional producing properties in the Appalachian
Basin and Michigan Basin, accounting for the remaining 1% of net proved
reserves. Eastern States owns approximately 151,000 gross acres in the Illinois
Basin, approximately 5,000 gross acres in the Michigan Basin, and approximately
an additional 7,000 gross acres outside the Appalachian, Michigan and Illinois
Basins.
DEVELOPMENT ACTIVITIES
Our development activities involve technical, economic, land, and field
investigations that result in the drilling of new wells, recompleting or
deepening existing wells and optimizing production systems. We pursue
opportunities which cost effectively maximize production from our properties. A
team composed of geologists, reservoir and production engineers, landmen, and
drilling supervisors identify these opportunities through their integrated
efforts. The teams also look for opportunities to farm-in or acquire additional
acreage and wells that enhance their area's performance. Certain properties we
deem uneconomic or non-strategic are farmed-out for exploitation by third
parties.
Development drilling accounts for approximately 95% of our drilling capital
expenditures. The remaining amount is used to conduct drilling within our
exploration project areas. Our experienced geoscience staff of six professionals
coordinate our exploration efforts in the Appalachian Basin with additional
support provided by consultants. Currently, our primary exploration targets are:
- Cambrian Rome sandstones of northeastern Kentucky;
- Knox carbonates and sandstones of eastern Ohio; and
- Devonian and Silurian horizons coincident with our southern West Virginia
acreage which can be tested by extending the drill depth of our shallower
development wells in this area by 200 to 1,000 feet.
A-10
<PAGE> 105
RESERVES
We operate producing properties primarily in West Virginia, Kentucky and
Ohio in the Appalachian Basin. We also own smaller producing properties in
Virginia, Michigan and Maryland. The following table shows quantities of our net
proved natural gas and oil reserves and cash flows at December 31, 1996, 1997
and 1998. The estimated future net cash flows and the present value of estimated
future net cash flows, discounted at 10%, presented below include the value of
Section 29 tax credits and future plugging and abandonment liabilities.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------
1996 1997 1998
-------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Proved developed:
Natural gas (MMcf).............................. 123,518 701,726 697,474
Oil (MBbls)..................................... 1,038 2,323 1,972
Proved undeveloped:
Natural gas (MMcf).............................. 46,404 309,567 352,240
Oil (MBbls)..................................... 87 14 32
Total proved:
Natural gas (MMcf).............................. 169,922 1,011,293 1,049,714
Oil (MBbls)..................................... 1,125 2,337 2,004
Estimated future net cash flows:
Before income tax............................... $495,748 $1,940,860 $2,157,655
After income tax................................ 340,150 1,393,163 1,524,826
Present value of estimated future net cash flows,
discounted at 10%:
Before income tax............................... $192,584 $ 680,432 $ 700,196
After income tax................................ 136,175 519,709 538,401
</TABLE>
Ryder Scott Company, L.P. reviewed the estimates prepared by Eastern States
of Eastern States' proved reserves and the future net cash flow and present
value of cash flow attributable to proved reserves at December 31, 1996, 1997
and 1998. As prescribed by the SEC, proved reserves were estimated using natural
gas and oil prices and production and development costs as of December 31 of
each year, without escalation.
The proved natural gas and oil reserves represent estimated quantities of
natural gas, oil and natural gas liquids which geological and engineering data
demonstrate to be recoverable in future years from known reservoirs under
existing economic and operating conditions. The proved reserves are further
classified as developed and undeveloped. The reserves described below and the
related standardized measures of discounted net cash flows are estimated only
and do not purport to reflect realizable values or fair market values of Eastern
States' reserves. Reserve estimates are inherently imprecise. Substantial
revisions to existing reserve estimates occur periodically due to additional
production history from each well, current-year drilling activity and other new
geologic or reserve characteristic information that may be discovered each year.
The standardized measure of discounted future net cash flows, which are
discounted at 10%, relating to proved natural gas and oil reserves is prescribed
by SFAS Statement No. 69, "Disclosures About Oil and Gas Producing Activities."
The statement requires measurement of future net cash flows through assignment
of a monetary value to proved reserve quantities and changes therein using a
standardized formula. The amounts shown above were developed as follows:
1. An estimate was made of the quantity of proved reserves and the future
periods in which they are expected to be produced based on year-end
economic conditions.
2. Year-end prices in effect for each respective year were applied to the
estimated quantities of year-end reserves. Prices remained constant,
except in instances where fixed and determinable gas price
A-11
<PAGE> 106
escalations are provided by contracts. The average prices used at December
31, 1996, 1997 and 1998 were $3.68, $2.57, and $2.71 per Mcf of natural
gas and $22.50, $15.00, and $9.00 per barrel of oil, respectively. For the
month of September 1999, the prevailing price of natural gas in the
Appalachian Basin for Columbia Gas Transmission, as reported by Inside
FERC, was $3.03 per MMbtu.
During 1999, Eastern States filed estimates of operated oil and natural gas
reserves as of December 31, 1998 with the U.S. Department of Energy on Form
EIA-23. These estimates are consistent with the reserves reported in this
appendix as of December 31, 1998.
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
The following table provides, at December 31, 1998, the summary calculation
of the standardized measure of discounted future net cash flows attributable to
our estimated net proved reserves at that date. These estimates, which we
prepared, have been reviewed by Ryder Scott Company L.P. Dollar amounts are
presented in millions. Natural gas and oil prices used in calculating estimated
values at December 31, 1998 were $2.71 per Mcf and $9.00 per Bbl of oil. For the
month of September 1999, the published price for natural gas in the Appalachian
Basin for Columbia Gas Transmission, as reported by Inside FERC, was $3.03 per
MMBtu. The posted price for Appalachian Basin oil at September 30, 1999, was
$21.25 per Bbl.
<TABLE>
<S> <C>
Future gross revenues...................................... $2,902
Future production costs.................................. (549)
Future development costs................................. (195)
------
Total future costs......................................... (744)
------
Future net revenues before future income taxes............. 2,158
Discount at 10% per annum.................................. (1,458)
------
Standardized measure before future income taxes............ 700
Discounted future income taxes............................. (162)
------
Standardized measure after future income taxes............. $ 538
======
</TABLE>
Future income taxes before discount were $633 million.
In computing this data, we used assumptions and estimates. We cannot assure
you that these assumptions and estimates will be indicative of future economic
conditions. We determined the future net revenues by using estimated quantities
of proved reserves and the periods in which they are expected to be developed
and produced based on December 31, 1998 economic conditions. The estimated
future production is priced as of December 31, 1998, except where fixed and
determinable price escalations are provided by contract. The resulting estimated
future gross revenues are reduced by estimated future costs to develop and
produce the proved reserves based on December 31, 1998 costs levels, but not for
debt service, general and administrative expenses and income taxes. Prices for
natural gas and oil are subject to substantial fluctuations as a result of
numerous factors. You should not construe the standardized measure as the
current market value of estimated natural gas and oil reserves. For additional
information concerning the discounted future net cash flows to be derived from
these reserves and the disclosure of the standardized measure information in
accordance with the provisions of Statement of Financial Accounting Standards
No. 69, you should review Note 13 to our consolidated financial statements
beginning on page AF-15 of this appendix.
Based upon the results of operations for the year ended December 31, 1998,
and excluding the effect of our hedging program, a change of $0.10 per Mcf in
the average price of natural gas throughout such period would result in
corresponding changes in operating and net income of $3.8 million and $2.5
million, respectively.
A-12
<PAGE> 107
ACREAGE AND PRODUCTIVE WELLS
The following table shows the approximate amount of our developed and
undeveloped acreage at December 31, 1998. Approximately 95% of our acreage is
held by production. Acres are presented in thousands.
<TABLE>
<CAPTION>
DEVELOPED
ACRES UNDEVELOPED ACRES TOTAL ACRES
----------- ----------------- ---------------
GROSS NET GROSS NET GROSS NET
----- --- ------ ------ ----- -----
<S> <C> <C> <C> <C> <C> <C>
Appalachian Basin...................... 332 298 1,073 966 1,405 1,264
Other.................................. 11 7 152 125 163 132
--- --- ----- ----- ----- -----
Total........................ 343 305 1,225 1,091 1,568 1,396
=== === ===== ===== ===== =====
</TABLE>
The following table shows at December 31, 1998 the number of producing
wells in which we own an interest and includes approximately 1,500 wells
associated with Section 29 tax credit monetization:
<TABLE>
<CAPTION>
TOTAL PRODUCING WELLS
----------------------
GROSS NET
----- ---
<S> <C> <C>
Natural Gas...................................... 5,732 5,388
Oil.............................................. 4 4
----- -----
Total.................................. 5,736 5,392
===== =====
</TABLE>
DRILLING ACTIVITIES
During the periods indicated, we drilled or participated in the drilling of
the following exploratory and development wells.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
-------------------------------------------- JUNE 30,
1996 1997 1998 1999
------------ ------------- ------------- -----------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory wells:
Productive.................... 5.0 3.0 4.0 2.3 3.0 2.4 2.0 2.0
Nonproductive................. 0 0 4.0 2.2 4.0 3.5 1.0 0.5
Development wells:
Productive.................... 73.0 71.5 116.0 113.0 171.0 168.1 59.0 58.5
Nonproductive................. 1.0 1.0 1.0 1.0 1.0 0.5 0 0
----- ---- ----- ----- ----- ----- ---- ----
Total................. 79.0 75.5 125.0 118.5 179.0 174.5 62.0 61.0
</TABLE>
As of July 31, 1999, we were drilling nine wells in the Appalachian Basin.
NET PRODUCTION, UNIT PRICES AND COSTS
Our lease operating expenses, including both well tending and gathering and
compression costs, averaged $0.41 per Mcfe for the year ended December 31, 1998
and $0.40 per Mcfe for the six months ended June 30, 1999. Over the past three
fiscal years we have reduced our drilling cost per well in the region by
approximately 10%.
A-13
<PAGE> 108
The following table provides information with respect to our net production
and average unit prices and costs for the periods indicated. Since natural gas
represents over 98% of our production, this information is presented in Bcfe or
Mcfe:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------ ----------------
1996 1997 1998 1998 1999
------ ------ ------ ----- -----
<S> <C> <C> <C> <C> <C>
Production (wellhead):
Gas Equivalents (Bcfe)..................... 6.6 24.7 38.7 19.5 20.0
Average sales price (hedged):
Gas Equivalents ($/Mcfe)................... $2.76 $2.62 $2.46 $2.57 $2.66
Average sales price (unhedged):
Gas Equivalents ($/Mcfe)................... $2.94 $2.80 $2.28 $2.41 $2.26
Average lease operating expenses ($/Mcfe).... $0.40 $0.55 $0.41 $0.41 $0.40
</TABLE>
MARKETING AND CONTRACTS
General. The close proximity of Appalachian production to a substantial
number of industrial and commercial end users in the northeastern United States
has traditionally provided producers a premium to Henry Hub, Louisiana prices.
This premium has averaged $0.26 per MMBtu over the past three calendar years.
For the period 1991 through 1998, wellhead natural gas prices in the Appalachian
Basin have averaged on an annual basis $0.25 per MMbtu more than Henry Hub and
NYMEX wellhead natural gas prices. During these eight years, the Appalachian
Basin annual premium has ranged from $0.14 per MMbtu to $0.47 per MMbtu over
NYMEX prices. In addition to its location premium, our Appalachian Basin gas
production has a higher Btu, or energy, content than natural gas produced in
many other areas of the United States, which also results in premium pricing
since index prices are typically based on an energy content of 1,000 Btu per
cubic foot.
We balance our spot and term natural gas sales to end-users and local
distribution companies and utilize multiple pricing structures. Eastern States
currently has two significant market-based contracts, one with affiliates of CNG
Transmission Corp. and the other with its own affiliate, Statoil Energy
Services, Inc. Each of these contracts expires in October 2000. In 1998, over
80% of the natural gas produced by Eastern States was sold under these
contracts, with 59% sold to Statoil Energy Services and 23% sold to CNG. During
the six months ended June 30, 1999, 60% of our natural gas was sold to Statoil
Energy Services and 30% to CNG. Eastern States believes that it will be able to
sell its natural gas under comparable terms should these contracts not be
renewed. Substantially all of our remaining natural gas is sold pursuant to
multi-month and/or one-year term agreements.
CNG. Under the CNG contract, affiliates of CNG purchase natural gas from
Eastern States based on the terms contained in confirmations which the parties
enter into from time to time. The CNG confirmations set forth the following:
- quantity;
- price;
- delivery point; and
- effective period of the confirmation.
The price under the CNG contracts has historically been based on the
published price of Inside FERC-Appalachian Basin for CNG, plus a premium based
on the higher Btu content, less applicable gathering, compression and processing
fees. The price for the natural gas is inclusive of all taxes levied on
production or transportation of the natural gas up to the delivery point.
Payment from the CNG affiliates are due by the 55th day following delivery.
A-14
<PAGE> 109
Each CNG confirmation sets forth the quantity of natural gas to be
delivered by Eastern States to the delivery point. The delivery point is, in
general, the point of the interconnection of Eastern States' gathering
facilities with the metering facilities of CNG's pipeline system. Eastern States
is responsible for delivery of natural gas to the delivery point. Title and risk
of loss to the natural gas pass to the CNG affiliate at the designated delivery
point.
Each CNG confirmation sets forth the period of time that the terms of the
confirmation are effective. The effective period of a confirmation with the CNG
affiliates has typically been for 12 months.
Statoil Energy Services. The contract with Statoil Energy Services is also
based on the terms contained in confirmations similar to the CNG confirmations
which the parties enter into from time to time.
The price under the Statoil Energy Services contract has historically been
based on the published price of Inside FERC -- Appalachian Basin for Columbia
Gas Transmission Corp. for natural gas delivered into Columbia Gas
Transmission's pipeline system, plus a premium based on the higher Btu content,
less applicable gathering, compression and processing fees. Eastern States is
responsible for all taxes attributable to the natural gas before the delivery
point. Statoil Energy Services is responsible for all taxes attributable to the
natural gas after the delivery point. Payment from Statoil Energy Services is
due by the 55th day following delivery.
Each confirmation with Statoil Energy Services sets forth the quantity of
natural gas to be delivered by Eastern States to the delivery point. Title and
risk of loss pass to Statoil Energy Services at the delivery point.
Each confirmation also sets forth the period of time that the terms of the
confirmation are effective. The effective period of a confirmation with Statoil
Energy Services has historically been for 12 months.
Third Party Services. Our 3,500 miles of Appalachian Basin gathering lines
provide us with the opportunity to purchase or transport third party gas
supplies for delivery into major interstate pipelines. We generally make these
purchases along our gathering pipeline systems, but also make purchases
off-system. Frequently, we market gas for joint venture partners. Our gathering
systems have enabled us to generate gross margins approximating $0.25 per MMBtu
over the past three years on third party volumes. Providing gathering services
to third parties allows Eastern States to obtain reimbursement for compressor
fuel and line loss amounts.
Domestic Customers. We also serve domestic customers at rates established
by state regulatory authorities. Revenues from these sales represent less than
1% of total revenues.
Hedging and Risk Management. We utilize forward sales of our production in
order to lock-in prices that we determine to be attractive and to achieve a
certain return on investment. In fiscal years 1996, 1997 and 1998, we hedged
approximately 70%, 70% and 60%, respectively, of our natural gas production.
This strategy has been successful in achieving our income goals. However, it has
limited our potential gains from increases in market prices. At June 30, 1999,
we had the following open natural gas hedges:
<TABLE>
<CAPTION>
MMBTU PER DAY DATE AVERAGE NYMEX PRICE PER MCF
- ------------- ---- ---------------------------
<C> <S> <C>
105 July 1999 to December 1999 $ 2.24
80 Year 2000 2.36
20 Year 2001 2.36
10 Years 2002 to 2008 2.35 to 2.45
30 April to October in years 2000 to 2003 2.10 to 2.30
</TABLE>
In addition to our natural gas hedges, we have hedged a small amount of our
oil production and Appalachian Basin premium. We plan to continue to hedge our
natural gas production, which will exclude the production attributable to the
trust in the future in order to reduce our exposure to significant declines in
the market price to ensure minimum levels of cash flow from our sales of oil and
gas. At the time we divest of any of our oil and gas properties, including the
sale of oil and gas properties to the trust as
A-15
<PAGE> 110
contemplated herein, we would close out our hedging positions and include the
gain or loss, resulting from the hedges as a part of the property sale for
financial reporting purposes. At no time does the Company enter into speculative
positions.
SECTION 29 TAX CREDITS
The Crude Oil Windfall Profits Tax Act of 1980 amended the Internal Revenue
Code to provide an incentive for natural gas production from unconventional
sources such as the Devonian Shale and tight sandstone formations of the
Appalachian Basin. Under Section 29 of the Internal Revenue Code, an owner of an
economic interest in natural gas production can qualify for income tax credits
on qualified production that is produced through December 31, 2002.
As part of our acquisition of Blazer Energy, we acquired Blazer Energy's
working interests in approximately 1,450 gross wells that qualified for Section
29 tax credits under the Internal Revenue Code. In December 1997, we transferred
substantially all the wells that qualified for Section 29 tax credits to our
subsidiary Eastern Seven, LLC. Eastern Seven then entered into an agreement
under which it monetized the value of its future Section 29 tax credits. Under
the terms of the agreement, Eastern Seven transferred title to these wells to a
trust, but retained a production payment and a note that entitle Eastern Seven
to all of the cash flow from the properties until approximately 95% of the
pre-tax net present value of the presently projected future production from the
properties has been received, which is expected to occur in the year 2018. In
addition to the note and production payment, Eastern Seven received a fixed cash
payment of $7.9 million at closing and will receive quarterly payments through
2002 equal to a specified percentage of the Section 29 tax credits generated
from the properties. These quarterly payments are expected to decline from
approximately $2.3 million per quarter in 1998 to approximately $1.9 million per
quarter in 2002.
In April 1999, we conveyed approximately 100 wells qualifying for Section
29 tax credits to Eastern Seven, LLC. Eastern Seven then entered into a
monetization agreement under similar terms and received a fixed cash payment of
$0.5 million at closing and will receive quarterly payments through 2002 equal
to a specified percentage of the Section 29 tax credits generated from the
properties. These quarterly payments are expected to decline from approximately
$117,000 per quarter in 1999 to approximately $107,000 per quarter in 2002.
Based on current law, Devonian Shale and tight sand tax credits will be
available until December 31, 2002. Eastern Seven has the option to repurchase
the properties after December 31, 2002 at the fair market value of the
properties at the time of repurchase less the value of the outstanding note and
production payment. Eastern States also entered into a management services
agreement with the trust pursuant to which Eastern States manages and operates
the properties on behalf of the trust.
RELATIONSHIP WITH STATOIL ENERGY
In August 1999, Statoil Energy Holdings agreed to combine and extend to
December 31, 2001 the final repayment dates of various notes payable to Statoil
Energy Holdings aggregating approximately $505 million of indebtedness at
December 31, 1998. This note has an 8% annual rate of interest, payable
semi-annually on January 1 and July 1 each year. At September 30, 1999, the
total amount of outstanding indebtedness under the note payable to Statoil
Energy Holdings was approximately $505 million and our intercompany indebtedness
owed to affiliates of Statoil Energy was approximately $51 million.
Since 1997, Eastern States, along with Statoil Energy and Statoil Energy
Holdings, has participated in a tax allocation agreement whereby all required
federal income tax returns for 1997 and thereafter are filed on a consolidated
basis. For each tax period, each subsidiary computes its separate tax liability
or receivable on a separate company basis. Any subsidiary tax liability is paid
to Statoil Energy by the subsidiary or, if there is a subsidiary tax benefit,
Statoil Energy will reimburse the subsidiary.
A-16
<PAGE> 111
In 1997, Eastern States sold the Gulf of Mexico properties acquired in the
Blazer acquisition in July 1997 to Eastern States' affiliate Statoil Exploration
U.S., Inc., an indirect wholly owned subsidiary of The Statoil Group, for
approximately $82 million.
Substantially all full-time employees of Eastern States participate in a
profit-sharing plan sponsored by Statoil Energy that includes an employee
savings feature under Section 401(k) of the Internal Revenue Code. Participants
in the plan may elect to defer up to 15% of their total compensation through
contributions to the plan and Statoil Energy matches 50% of employee
contributions up to 6% of an employee's total compensation. Statoil Energy's
matching vests within five years.
As described in more detail under the heading "Eastern States Oil & Gas,
Inc." on page A-1, The Statoil Group has decided to sell its equity ownership in
Statoil Energy, including Eastern States.
COMPETITION
Competition in our primary producing areas is intense. We actively compete,
in some cases against companies with substantially larger financial and other
resources, in the:
- acquisition of producing properties and natural gas and oil leases;
- marketing of natural gas and oil; and
- obtaining goods, services and labor.
There are numerous exploration and production companies in the Appalachian
Basin that compete directly with Eastern States. Only two of these have similar
daily volume production, leasehold acreage and proved natural gas reserves as
compared to Eastern States. These two companies are owned by U.S. natural gas
utilities who have regulated local gas distribution and interstate gas
transmission subsidiaries, in addition to their exploration and production
subsidiary. Both of these companies have active drilling programs and directly
compete with Eastern States. We have substantial relationships with both of
these companies to gather and transmit our natural gas.
To the extent that our gas supply, gathering systems, organization or
development budget are smaller than those of some of our competitors, we may be
disadvantaged in our competitive activities. We believe that our competitive gas
marketing position is based on location, price, contract terms, quality of
service and reliable delivery record. We believe that our extensive acreage
position, substantial ongoing development program and existing gas gathering
systems give us a competitive advantage over other producers in the Appalachian
Basin that do not have similar systems or facilities in place.
TITLE TO PROPERTIES
As is customary in the natural gas and oil industry, we make only a cursory
review of title to farm-out acreage and to undeveloped natural gas and oil
leases upon execution of the contracts. Prior to the commencement of drilling
operations, a thorough title examination may be conducted and curative work may
be performed with respect to significant defects. To the extent title opinions
or other investigations reflect title defects, we, rather than the seller of the
undeveloped property, are typically responsible to cure any such title defects
at our expense. If we were unable to remedy or cure any title defect of a nature
such that it would not be prudent to commence drilling operations on the
property, we could suffer a loss of our entire investment in the property. We
believe that we have satisfactory title to the properties in accordance with
standards generally accepted in the oil and gas industry. Our natural gas and
oil properties are subject to customary royalty interests, liens for current
taxes and other burdens that we believe do not materially interfere with the use
of or affect the value of such properties.
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GOVERNMENT REGULATION
Regulation of Natural Gas and Oil Exploration and Production
Our exploration and production operations are subject to various types of
regulation at the federal, state and local levels. This regulation includes:
- requiring permits for the drilling of wells;
- maintaining bonding requirements in order to drill or operate wells; and
- regulating the location of wells, the method of drilling and casing
wells, the surface use and restoration of properties upon which wells are
drilled and the plugging and abandonment of wells.
Our operations are also subject to various conservation laws and
regulations. These laws and regulations may include:
- the density or spacing of wells that may be drilled;
- the unitization or pooling of oil and gas properties; and
- the regulation of the maximum rate of production from natural gas and oil
wells.
The effect of these regulations may limit the amounts of natural gas and
oil that we can produce from our wells, and limit the number of wells or the
locations at which we can drill. Legislation affecting the oil and gas industry
also is under constant review for amendment or expansion. In addition, numerous
departments and agencies, both federal and state, are authorized by statute to
issue rules and regulations binding on the natural gas and oil industry and its
individual members, some of which carry substantial penalties for failure to
comply. The regulatory burden on the natural gas and oil industry increases our
cost of doing business and, as a result, affects our profitability. Because laws
and regulations are frequently expanded, amended and reinterpreted, we are
unable to predict the future cost or impact of complying with any laws and
regulations.
Federal Regulation of Gas.
Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission
regulates the interstate transportation and the sale in interstate commerce for
resale of natural gas. The FERC's jurisdiction over interstate natural gas sales
was substantially modified by the Natural Gas Policy Act, under which the FERC
continued to regulate the maximum selling prices of specified categories of gas
sold in "first sales" in interstate and intrastate commerce. Effective January
1, 1993, however, the Natural Gas Wellhead Decontrol Act deregulated natural gas
prices for all "first sales" of natural gas. Because "first sales" include
typical wellhead sales by producers, all natural gas produced from Eastern
States' natural gas properties is being sold at market prices, subject to the
terms of any private contracts which may be in effect. The FERC's jurisdiction
over natural gas transportation was not affected by the Decontrol Act.
Eastern States' sales of natural gas are affected by intrastate and
interstate gas transportation regulation. Beginning in 1985, the FERC adopted
regulatory changes that have significantly altered the transportation and
marketing of natural gas. These changes were intended by the FERC to foster
competition by, among other things, transforming the role of interstate pipeline
companies from wholesale marketers of gas to the primary role of gas
transporters. All gas marketing by the pipelines was required to be divested to
a marketing affiliate, which operates separately from the transporter and in
direct competition with all other merchants. As a result of the various omnibus
rulemaking proceedings in the late 1980s and the individual pipeline
restructuring proceedings of the early to mid-1990s, the interstate pipelines
are now required to provide open and nondiscriminatory transportation and
transportation-related services to all producers, gas marketing companies, local
distribution companies, industrial end users and other customers seeking
service. Through similar orders affecting intrastate pipelines that provide
similar interstate services, the FERC expanded the impact of open access
regulations to intrastate commerce.
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<PAGE> 113
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing, including:
- the large-scale divestiture of interstate pipeline-owned gas gathering
facilities to affiliated or non-affiliated companies;
- further development of rules governing the relationship of the pipelines
with their marketing affiliates;
- the publication of standards relating to the use of electronic bulletin
boards and electronic data exchange by the pipelines to make available
transportation information on a timely basis and to enable transactions
to occur on a purely electronic basis;
- further review of the role of the secondary market for released pipeline
capacity and its relationship to open access service in the primary
market; and
- development of policy and promulgation of orders pertaining to its
authorization of market-based rates, rather than traditional
cost-of-service based rates, for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in
the relevant service market. We cannot predict what effect the FERC's
other activities will have on the access to markets, the fostering of
competition and the cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. Eastern States believes
these changes generally have improved the access to markets for its natural gas
while, at the same time, substantially increasing competition in the natural gas
marketplace. We cannot predict what new or different regulations the FERC and
other regulatory agencies may adopt, or what effect subsequent regulations may
have on production and marketing of gas from our properties.
In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation and the promotion of competition in the gas industry. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints previously applicable. There are
other legislative proposals pending in the Federal and state legislatures which,
if enacted, would significantly affect the petroleum industry. At the present
time, we cannot predict what proposals, if any, Congress or the various state
legislatures might actually enact and what effect, if any, these proposals might
have on our production and marketing of gas. Similarly, and despite the trend
toward federal deregulation of the natural gas industry, we cannot predict
whether or to what extent that trend will continue, or what the ultimate effect
will be on our production and marketing of gas.
Federal Regulation of Petroleum.
Eastern States' sales of oil are not regulated and are at market based
prices. The price received from the sale of these products is affected by the
cost of transporting the products to market. Much of that transportation is
through interstate common carrier pipelines. Effective as of January 1, 1995,
the FERC implemented regulations generally grandfathering all previously
approved interstate transportation rates and establishing an indexing system for
those rates by which adjustments are made annually based on the rate of
inflation, subject to certain conditions and limitations. These regulations may
tend to increase the cost of transporting oil and natural gas liquids by
interstate pipeline, although the annual adjustments may result in decreased
rates in a given year. These regulations have generally been approved on
judicial review. Every five years, the FERC will examine the relationship
between the annual change in the applicable index and the actual cost changes
experienced by the oil pipeline industry. The first such review is scheduled for
the year 2000. We are not able to predict with certainty what effect, if any
these relatively new federal regulations nor the periodic review of the index by
FERC will have on it.
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Safety and Health Regulation
Our gathering operations are subject to occupational safety, health and
operational regulations relating to the design, installation, testing,
construction, operation, replacement and management of facilities. Pipeline
safety issues have recently been the subject of increasing focus in various
political and administrative arenas at both the state and federal levels. We
believe our operations, to the extent they may be subject to current natural gas
pipeline safety or other health and safety requirements, comply in all material
respects with these requirements. We cannot predict what effect, if any, the
adoption of additional pipeline safety or other safety and health legislation
might have on our operations, but the industry could be required to incur
additional capital expenditures and increased costs depending upon future
legislative and regulatory changes.
ENVIRONMENTAL MATTERS
Our operations are subject to federal, state and local laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Numerous governmental agencies issue rules and
regulations to implement and enforce these laws, which may be costly to comply
with and carry substantial penalties for failure to comply. These laws and
regulations may:
- require the acquisition of one or more permits before drilling commences;
- restrict the types, quantities and concentration of various substances
that can be released into the environment in connection with drilling and
production activities;
- limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas;
- require measures to prevent the release of contaminants into the
environment from former operations, such as the remediation of former or
current well sites, including pit closure and plugging abandoned wells;
and
- impose substantial liabilities and penalties if any contaminants are
released into the environment as a result of our operations.
In addition, these laws, rules and regulations may restrict the rate of oil
and natural gas production below the rate that would otherwise exist or may
require that certain wells be shut-in. The regulatory burden on the natural gas
and oil industry increases the cost of doing business and consequently affects
our profitability and the profitability of others in the industry. Our
expenditures in the near future for regulatory and environmental compliance are
not expected to be material in relation to our total capital expenditure
program; however, we cannot predict the ultimate cost of compliance because
costs are highly dependent on the facts and circumstances of a particular
situation and environmental laws and regulations frequently change. Although we
believe that our operations and facilities are in compliance in all material
respects with current applicable environmental regulations, risks of substantial
costs and liabilities are inherent in gas and oil operations, and we cannot
assure you that we will not incur significant costs and liabilities in the
future. A change in current environmental laws and regulations could have an
adverse effect on our financial condition and results of operations.
CERCLA
The Comprehensive Environmental Response, Compensation and Liability Act,
which is commonly known as CERCLA and also as the Superfund law, imposes
liability, without regard to fault or the legality of the original conduct, on
persons who are considered to be responsible for the release of a hazardous
substance into the environment. While most oil and gas exploration and
production wastes are not considered hazardous substances, there may be some
materials present at an oil and gas well or used in oil and gas exploration and
production operations that are considered hazardous substances. Persons who may
be liable under CERCLA, usually referred to as potentially responsible parties,
include the current or former owner or operator of the disposal site or sites
where the release occurred and companies that
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<PAGE> 115
disposed or arranged for the disposal of the hazardous substances found at a
site and companies that transported the hazardous substance for disposal. Under
CERCLA, potentially responsible parties may be subject to joint and several
liability for the costs of cleaning up hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of some health studies. In addition, where a release of a hazardous
substance has occurred, it is not uncommon for neighboring landowners and other
third parties to file lawsuits claiming for personal injury and property damage
allegedly caused by hazardous substances or other pollutants released into the
environment.
Stricter standards in environmental legislation may be imposed on the oil
and gas industry in the future. For instance, from time to time legislation has
been proposed in Congress that would reclassify certain oil and natural gas
exploration and production wastes as "hazardous wastes" subject to more
stringent handling, disposal and cleanup requirements. If such legislation were
enacted, it could have a significant impact on our operating costs, as well as
the oil and gas industry in general. Furthermore, although petroleum, including
oil and natural gas, is exempt from CERCLA, at least two courts have ruled that
certain wastes associated with the production of oil may be classified as
hazardous substances under CERCLA. State initiatives to regulate further the
disposal of oil and natural gas wastes are pending in several states, and these
initiatives could have a similar impact on us. Although future changes in
federal and state law related to discharge into navigable waters or state waters
could have a significant impact on our operating costs, the entire industry will
experience a similar impact and we believe that the increased costs will not
have a material adverse impact on our financial conditions and operations.
Solid and Hazardous Waste
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976, which is commonly known as RCRA,
regulates the generation, transportation, storage, treatment and disposal of
hazardous wastes, and can require cleanup of hazardous waste disposal sites.
RCRA currently excludes drilling fluids, produced waters and other wastes
associated with the exploration, development or production of natural gas and
oil from the definition of hazardous waste. Disposal of non-hazardous oil and
gas exploration, development and production wastes may be regulated by state
law. In addition, we occasionally handle material that may be classified as
hazardous waste under RCRA. RCRA and state laws impose certain operational
requirements upon the storage, handling and disposal of these materials.
LITIGATION
Various legal actions that have arisen in the ordinary course of business
are pending with respect to Eastern States and its affiliates. We do not expect
any of these proceedings to have a material adverse impact on our results of
operations or financial position.
OPERATING HAZARDS AND UNINSURED RISKS
Our operations are subject to hazards and risks inherent in drilling for
and production and transportation of oil and natural gas, such as:
- fires;
- natural disasters;
- explosions;
- encountering formations with abnormal pressures;
- blowouts;
- cratering;
- pipeline ruptures; and
- spills,
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any of which can result in loss of hydrocarbons, environmental pollution,
personal injury claims, and other damage to our properties and properties of
others. As protection against operating hazards, we maintain insurance coverage
against some, but not all, potential losses. We believe that our insurance is
adequate and customary for companies of a similar size engaged in operations
similar to ours, but losses could occur for uninsurable or uninsured risks or in
amounts in excess of existing insurance coverage. The occurrence of an event
that is not fully covered by insurance could have an adverse impact on our
financial condition and results of operations.
EMPLOYEES
As of June 30, 1999, we had 276 employees in eight offices. We believe that
our relations with our employees are satisfactory. We have not entered into any
collective bargaining agreements with any of our employees.
OFFICES
Statoil Energy maintains its corporate headquarters in Alexandria, Virginia
where it leases approximately 110,000 square feet of office space. Eastern
States maintains its corporate headquarters in the same building and subleases
approximately 17% or 19,000 square feet of the office space from Statoil Energy.
We also have a regional office in Charleston, West Virginia, with field offices
in Weston, West Virginia; Madison, West Virginia; Brenton, West Virginia;
Pikeville, Kentucky; Ravenna, Ohio; and Cambridge, Ohio.
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SELECTED FINANCIAL INFORMATION
The following table shows selected historical financial information for
Eastern States Oil & Gas, Inc. and reflects the acquisition of the domestic
natural gas and oil producing properties of Blazer Energy Corp. in July of 1997.
The selected historical financial information as of and for the three years
ended December 31, 1998 have been derived from our audited consolidated
financial statements. The summary historical financial information for the two
years ended December 31, 1995 and for the six months ended June 30, 1998 and
1999 has been derived from our unaudited financial statements. The results for
the six months ended June 30, 1999 are not necessarily indicative of the results
that may be expected for any other period or for the full year. The following
information should be read in conjunction with our financial statements and the
notes thereto and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" contained elsewhere in this appendix.
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS
DECEMBER 31, YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------ -------------------------------- --------------------
1994 1995 1996 1997 1998 1998 1999
------- ------- -------- -------- -------- -------- --------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Total revenues............ $1,772.. $ 4,852 $ 18,247 $ 65,368 $104,670 $ 54,677 $ 57,723
------- ------- -------- -------- -------- -------- --------
Operating expenses........ 623 1,244 2,655 13,454 15,950 7,927 8,043
Depreciation, depletion
and amortization........ 550 1,429 4,783 19,073 31,517 16,520 16,129
General and administrative
expenses................ -- -- 1,630 3,254 5,462 2,249 2,868
------- ------- -------- -------- -------- -------- --------
Total costs and
expenses................ 1,173 2,673 9,068 35,781 52,929 26,696 27,040
------- ------- -------- -------- -------- -------- --------
Operating income.......... 599.... 2,179 9,179 29,587 51,741 27,981 30,683
Interest expense, net of
interest income......... 518 2,061 4,338 21,608 38,952 19,513 21,265
------- ------- -------- -------- -------- -------- --------
Income before income
taxes................... 81 118 4,841 7,979 12,789 8,468 9,418
Income tax expense
(benefit)............... -- -- 956 (1,171) 4,443 3,112 3,372
------- ------- -------- -------- -------- -------- --------
Net income................ $ 81 $ 118 $ 3,885 $ 9,150 $ 8,346 $ 5,356 $ 6,046
======= ======= ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Net cash provided by (used
for)
Operating activities.... (177) 40,341 10,301 12,244 40,511 22,081 24,818
Investing activities.... (19,173) (28,641) (56,571) (514,809) (56,551) (506) (21,061)
Financing activities.... 19,500 (12,499) 46,270 502,565 16,040 (21,575) (3,757)
Capital expenditures...... 19,173 28,641 56,789 597,007 82,525 25,045 21,990
BALANCE SHEET DATA (AT END
OF PERIOD):
Working capital........... 638 (1,979) (2,133) 10,057 13,215 12,709 13,412
Oil and gas properties,
net..................... 18,336 40,683 96,770 589,889 615,611 573,857 620,873
Total assets.............. 19,945 45,564 100,469 626,339 658,333 602,472 651,867
Total long-term debt...... 19,500 41,366 69,633 503,588 505,488 505,488 505,488
Stockholder's equity...... 81 1,700 5,585 64,735 73,081 70,090 79,127
</TABLE>
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<PAGE> 118
SUMMARY RESERVE AND OPERATING DATA
The following shows summary reserve and operating information as of and for
the periods indicated. Calculation of the standardized measure is made using a
10% discount rate in accordance with the rules and regulations of the SEC and
includes the value of Section 29 tax credits and future plugging and abandonment
liabilities. The reserve to production ratio presented below represents year-end
reserves divided by that year's production. For additional information regarding
our proved reserves as reviewed by Ryder Scott Company, L.P. and other
information regarding our gas and oil reserves, see "Business and
Properties -- Reserves" and Note 13 to our consolidated financial statements
presented on page AF-15 of this appendix.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1994 1995 1996 1997 1998
------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
NET PROVED RESERVES (AT END OF PERIOD):
Natural gas (Bcf)......................... 38 82 170 990 1,050
Oil (MMBbls).............................. -- -- 1 2 2
Total proved reserves (Bcfe).............. 38 83 177 1,025 1,062
Percent proved developed reserves......... 68% 75% 73% 69% 67%
Standardized measure before future income
taxes (in thousands).................... $27,539 $66,170 $192,584 $680,432 $700,196
Standardized measure after future income
taxes (in thousands).................... $21,145 $52,071 $136,175 $519,709 $538,401
Reserve to production ratio............... 51 40 27 45 29
AVERAGE DAILY PRODUCTION:
Natural gas (MMcf per day)................ 2 6 17 61 98
Oil (MBbls per day)....................... -- -- -- -- --
Total production (MMcfe per day).......... 2 6 18 63 100
YEAR END COMMODITY PRICES:
Natural gas ($/Mcf)....................... $ 2.55 $ 3.06 $ 3.68 $ 2.57 $ 2.71
Oil ($/Bbl)............................... $ 15.50 $ 16.50 $ 22.50 $ 15.00 $ 9.00
</TABLE>
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<PAGE> 119
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following information should be read in conjunction with the
information contained in our financial statements and the notes thereto included
elsewhere in this appendix.
OVERVIEW
As an independent energy producer, we are engaged in the exploration for
and the development, production, gathering, transportation, acquisition and
marketing of natural gas and oil primarily in the Appalachian Basin. We are
principally a natural gas producer, with natural gas making up over 98% of our
net revenue for the year ended December 31, 1998 and the six months ended June
30, 1999. Our average natural gas production increased from 2 MMcfe per day at
year-end 1994 to 104 MMcfe per day in the six-month period ended June 30, 1999.
Our results of operations are determined in large part by the differences
between the prices received for the natural gas produced and the cost to find,
develop, produce, transport and market such natural gas. Changes in sales price
received for our production directly affect our determination to proceed with
the development of natural gas and our quantity of proved reserves. In addition
to changes in supply and demand, natural gas and oil prices are influenced by
seasonal factors, natural gas transportation and storage infrastructure,
imports, political and regulatory developments and competition from other
sources of energy and have been volatile over the last three years. Final prices
for prompt month natural gas contracts traded on the NYMEX for delivery of gas
at Henry Hub, Louisiana, have ranged from a low of approximately $1.67 per MMBtu
to a high of approximately $4 per MMBtu during the period from January 1, 1996
to December 31, 1998. It is management's view that general price inflation did
not materially impact reported net sales, revenues or income for continuing
operations for the three years ended December 31, 1998. Our production volume
growth in recent years has occurred through exploration and development of our
core holdings, as well as from producing property acquisitions, the most
significant of which was the acquisition of Blazer Energy in July 1997 for $567
million.
Based upon the results of operations for the year ended December 31, 1998,
and excluding the effect of our hedging program, a change of $0.10 per Mcf in
the average price of natural gas throughout such period would result in
corresponding changes in operating and net income of $3.8 million and $2.5
million, respectively. We intend to continue to utilize hedging to limit our
exposure to significant declines in market prices and to ensure minimum levels
of cash flow from our sales of natural gas and oil. See "Business and
Properties -- Marketing and Contracts -- Risk Management."
We follow the full cost method of accounting for our natural gas and oil
exploration and production activities. Under this method, we capitalize all
productive and non-productive costs associated with acquisition, exploration and
development activities. The capitalized costs of producing natural gas and oil
properties are depreciated, depleted and amortized by the units-of-production
method based on estimated proved reserves.
We periodically review our proved properties in accordance with Rule
4-10(c)(4) of Regulation S-X to determine whether the unamortized capitalized
costs of such properties less related deferred income taxes, as reflected in our
accounting records, exceeds the estimated discounted future net revenues
attributable to the proved properties, as adjusted.
We periodically review our other properties to determine whether the
carrying value of such properties as reflected in our accounting records exceeds
the estimated undiscounted future net revenues attributable to such properties.
Based on this review and the continuing evaluation of development plans,
economics and other factors, if appropriate, we would record impairments
(additional depletion and depreciation) pursuant to Statement of Financial
Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed of," to the extent
that the net book values of its other properties exceed the expected discounted
future net revenues. Such impairments would constitute a charge to earnings
which does not impact our cash flow from operating activities. However, such
potential write-downs impact the amount of stockholders' equity and, therefore,
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the ratio of debt to equity. We have not incurred impairment charges for the
periods presented. No assurance can be given that we will not experience
impairments in the future.
RESULTS OF OPERATIONS
Operating results for Eastern States are presented in the tables and
analyses that follow.
OPERATING RESULTS
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
---------------------------- -----------------
1996 1997 1998 1998 1999
------- ------- -------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Salesmeter volumes (Bcfe)........... 6.5 23.0 36.5 18.4 18.8
Average realized salesmeter oil &
gas price (hedged) ($ per Mcfe)... 2.81 2.81 2.61 2.72 2.83
Oil & gas revenue (hedged).......... $18,247 $64,604 $ 95,315 $50,034 $53,149
Tax credit monetization............. -- 764 9,355 4,643 4,574
Total revenues...................... $18,247 $65,368 $104,670 $54,677 $57,723
Operating expenses.................. 2,655 13,454 15,950 7,927 8,043
Depreciation, depletion and
amortization...................... 4,783 19,073 31,517 16,520 16,129
General and administrative
expenses.......................... 1,630 3,254 5,462 2,249 2,868
Operating income.................... $ 9,179 $29,587 $ 51,741 $27,981 $30,683
</TABLE>
SIX MONTHS ENDED JUNE 30, 1998 COMPARED TO SIX MONTHS ENDED JUNE 30, 1999
Revenue for the six months ended June 30, 1999 was $57.7 million, or 5.5%
higher than the six months ended June 30, 1998. Natural gas and oil revenues
increased 6.2% to $53.1 million for the six months ended June 30, 1998, compared
to $50.0 million for the six months ended June 30, 1999. This increase was
principally due to higher produced volumes, which increased from 101.7 MMcfe per
day in 1998 to 103.8 MMcfe per day in 1999, and higher average realized selling
prices, which increased from $2.72 per Mcfe in 1998 to $2.83 per Mcfe in 1999.
Operating expenses increased 1.3% from $7.9 million for the six months
ended June 30, 1998 to $8.0 million for the six months ended June 30, 1999. This
increase was due principally to volume increases as operating expenses per Mcfe
for each period approximated $0.43 per Mcfe.
Depreciation, depletion and amortization decreased by 2.4% from $16.5
million for the six months ended June 30, 1998 to $16.1 million for the six
months ended June 30, 1999. This favorable change in the depreciation, depletion
and amortization rate per Mcfe, from $0.90 to $0.86, reflects favorable drilling
results for the period July 1998 to June 1999, which resulted in increased
proved developed and proved undeveloped gas reserves. The 4.5% decrease in the
depreciation, depletion and amortization rate was partially offset by additional
costs resulting from a 2.1% increase in volumes.
Selling, general and administrative expenses increased 27% from $2.2
million for the six months ended June 30, 1998 to $2.8 million for the six
months ended June 30, 1999. This increase was attributable to increased
investments in information technology.
Interest expense increased from $19.5 million for the six months ended June
30, 1998 to $21.3 million for the six months ended June 30, 1999. This increase
is directly attributable to higher spending in support of development efforts.
Eastern States has a credit facility with Statoil Energy Holdings which provides
for borrowings at a 8% annual fixed interest rate. Outstanding borrowings at
December 31, 1998 were $505.5 million.
Pre-tax income was $9.4 million and $8.5 million for the six months ended
June 30, 1999 and 1998, respectively. The effective income tax rate approximated
36% in each period.
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FISCAL YEAR ENDED DECEMBER 31, 1998 COMPARED TO FISCAL YEAR ENDED DECEMBER 31,
1997
Revenues for 1998 were $104.7 million, or 60% higher than 1997 revenues of
$65.4 million. The increase in revenues is attributable to the Blazer Energy
acquisition as of July 1, 1997, which increased daily production from 22.6
MMcfe/day to 100.0 MMcfe/day. Production increased 61% from approximately 23
Bcfe in 1997, based on one-half year of Blazer Energy volumes, to approximately
37 Bcfe in 1998. Section 29 tax credits monetized in December 1997, provided
$0.8 million and $9.4 million in additional revenues in 1997 and 1998,
respectively. The production increase was partially offset by a 7% decrease in
the realized gas price from $2.81 per Mcfe in 1997 to $2.61 per Mcfe in 1998.
Operating expenses increased nearly 18% from $13.5 million in 1997 to $15.9
million in 1998. This increase is principally due to a full year of Blazer
Energy operations in 1998. The Company successfully assimilated Blazer Energy
into its operations as operating costs per Mcfe were reduced significantly to
$0.44 per Mcfe in 1998 versus $0.59 per Mcfe in 1997.
Depletion, depreciation and amortization expenses were $0.86 per Mcfe or
$31.5 million in 1998 and $0.83 per Mcfe or $19.1 million in 1997. The higher
rate reflects investments in pipeline infrastructure, approximately $10 million
in total over the two-year period.
Selling, general and administrative expenses increased by 67% to $5.5
million in 1998 from $3.3 million in 1997, reflecting a full year of Blazer
Energy operations and higher development activity.
Interest expense increased from $21.6 million in 1997 to $38.9 million in
1998 as a result of the Blazer Energy acquisition which was funded principally
by additional borrowings from Statoil Energy Holdings. Borrowings from Statoil
Energy Holdings were subject to 8% annual rate of interest.
Income before taxes increased from $8.0 million in 1997 to $12.8 million in
1998. Eastern States was able to use approximately $2.2 million of tax credits
in 1997 to reduce income taxes. This as well as other available credits allowed
Eastern States to realize an income tax benefit of $1.2 million in 1997, while
it had a tax expense of $4.4 million in 1998.
FISCAL YEAR ENDED DECEMBER 31, 1997 COMPARED TO FISCAL YEAR ENDED DECEMBER 31,
1996
Revenue increased 29% from $18.2 million in 1996 to $65.4 million in 1997,
which is directly attributable to the July 1, 1997 Blazer Energy acquisition.
Production increased from 17.8 MMcfe/day to 100.0 MMcfe/day and accordingly,
total volume increased 254% from 6.5 Bcfe produced in 1996 to 23.0 Bcfe produced
in 1997. Since the realized selling price was approximately $2.81 per Mcfe in
both periods, the above revenue increase is solely attributable to the increase
in production as a result of the Blazer Energy acquisition.
Operating expenses increased from $2.7 million in 1996 to $13.5 million in
1997. This increase was the direct result of the Blazer Energy acquisition and
generally higher development activity.
Depletion, depreciation and amortization expenses were $0.83 per Mcfe, or
$19.1 million, in 1997 and $0.73 per Mcfe, or $4.8 million, in 1996. This dollar
increase is directly related to the increased production volumes resulting from
the Blazer Energy acquisition.
Selling, general and administrative expenses increased from $1.6 million in
1996 to $3.3 million in 1997, due to the additional office personnel and related
expenses associated with the Blazer Energy acquisition.
Interest expense increased from $4.3 million to $21.6 million as a result
of increased borrowings from Statoil Energy Holdings to fund the Blazer Energy
acquisition. Borrowings from Statoil Energy Holdings were based on a fixed
interest rate of 8% per annum.
Income before income taxes increased from $4.8 million in 1996 to $8.0
million in 1997. In 1997, Eastern States realized $2.2 million of tax credits.
This, along with other available credits, resulted in a tax benefit of $1.2
million in 1997, compared to tax expense of $1.0 million in 1996.
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<PAGE> 122
LIQUIDITY AND CAPITAL RESOURCES
Eastern States' primary capital resources are net cash provided by
operating activities and net proceeds from financing activities, including
borrowings from Statoil Energy Holdings. We expect our future capital
requirements, primarily consisting of development expenditures, to be funded by
cash flow from operations and financing activities.
Our levels of cash flows and earnings depend on many factors, including the
price of natural gas and our ability to maintain low operating costs and
overhead. We cannot predict natural gas prices which fluctuate based on market
conditions and seasonality. Our average realized natural gas price was $2.81 per
Mcfe for each of 1996 and 1997 and decreased to $2.61 per Mcfe in 1998.
For the six month period ended June 30, 1999, our net development
expenditures of approximately $21 million were entirely funded by net cash
provided from operating activities in the amount of approximately $24.8 million.
Cash provided by operating activities was $40.5 million, $12.2 million, and
$10.3 million in 1998, 1997, and 1996, respectively. The increase from 1997 to
1998 was primarily due to increased revenues and production associated with the
Blazer Energy acquisition. Before changes in working capital, cash flow from
operations was $43.7 million, $24.4 million, and $9.6 million in 1998, 1997, and
1996, respectively. For the year 1999, our capital expenditures are expected to
be $70 million. For the year 2000, our capital expenditures are expected to be
approximately $65 million.
FINANCIAL CONDITION
Total assets increased 5.1% from $626 million at December 31, 1997 to $658
million at December 31, 1998, primarily because of development drilling. As of
December 31, 1998, total capitalization of Eastern States was $631 million, of
which 80% was long-term debt. This compares with capitalization of $606 million
at December 31, 1997, of which 83% was long-term debt.
In an effort to improve Eastern States' liquidity and financial condition,
in August 1999, Statoil Energy Holdings agreed to combine and extend to December
31, 2001 the final repayment dates of various notes payable to Statoil Energy
Holdings aggregating approximately $505 million at December 31, 1998. Of the
amount rescheduled, $428 million was originally due to be paid in June 2000 with
the remainder being payable during 1999. This note has an 8% annual rate of
interest, payable semi-annually on January 1 and July 1 each year. At September
30, 1999, the total amount of outstanding indebtedness under the note payable to
Statoil Energy Holdings was approximately $505 million.
WORKING CAPITAL
Eastern States generally uses available cash to minimize intercompany
indebtedness and, therefore, maintains minimal cash and cash equivalent
balances. Short-term liquidity needs are satisfied by either advances from
Statoil Energy or Statoil Energy Holdings. Working capital of $13.2 million at
December 31, 1998 is primarily attributable to the excess of accounts receivable
over accounts payable.
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<PAGE> 123
CAPITAL EXPENDITURES
The table below sets forth the components of our historical capital
expenditures for the two-years ended December 31, 1997 and 1998 and the
six-month periods ended June 30, 1998 and 1999.
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED JUNE 30,
------------------ -----------------
1997 1998 1998 1999
-------- ------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Exploration................................... $ 2,531 $ 2,427 $ 1,063 $ 1,000
Development................................... 22,743 69,667 20,696 22,219
Lease acquisition............................. 1,401 345 (225) 205
Proved property acquisition................... 567,135 8,403 2,368 (1,826)
-------- ------- ------- -------
Total............................... $593,810 $80,842 $23,902 $21,598
======== ======= ======= =======
</TABLE>
Our ability to maintain and increase our operating income and cash flow is
dependent upon continued capital spending. We expect our capital expenditures in
1999 to be approximately $70 million and approximately $65 million in the year
2000. We currently expect to drill 200 to 230 net development wells in the
Appalachian Basin during 1999. Our level of capital expenditures may vary in the
future depending on a number of factors, including energy market conditions and
other related economic factors. We have no material long-term commitments
associated with expenditure plans.
Management believes that expected cash flow from operations supplemented by
borrowings, as needed, from Statoil Energy Holdings will be sufficient to fund
its capital expansion plans and working capital requirements. Future cash flows,
however, are dependent on a number of variables, such as the level of production
of natural gas and oil and the sales price of natural gas and oil. Accordingly,
management cannot guarantee that future operations will provide cash in
sufficient amounts to maintain current levels of capital expenditures or to meet
our debt service requirements.
To date, we have not spent significant amounts to comply with environmental
or safety regulations, and we currently do not expect to do so during 1999.
However, developments such as new regulations, enforcement policies or claims
for damages could result in significant future costs.
YEAR 2000
"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant by January 1, 2000 may cause material adverse
effects to companies and organizations that rely upon those systems. Continuity
of our operations in January 2000 will depend not only on the performance of our
computer systems, but also on the compliance of computer systems and
computer-controlled equipment of third parties. These third parties include oil
and natural gas purchasers and significant service providers such as electric
utility companies and natural gas plant, pipeline and gathering system
operators.
Eastern States has reviewed its computer systems and is making the
necessary modifications for Year 2000 compliance. Eastern States is completing
modifications and testing of its land computer programs and expects to complete
remediation and testing by the end of November 1999. The remaining computer
systems have been assessed and are believed to be compliant.
Some of Eastern States' critical field equipment, such as natural gas
compressors, are partially controlled or regulated by embedded computer chips.
Based on a preliminary review of all operating areas, Eastern States has
identified no significant compliance exceptions. Based on its review,
remediation efforts and the results of testing to date, Eastern States does not
believe that timely modification of its computer systems for Year 2000
compliance represents a material risk. Eastern States estimates that total costs
related to Year 2000 compliance efforts will be approximately $200,000 of which
approximately $130,000 has been incurred and expensed through September 30,
1999.
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<PAGE> 124
Eastern States has identified significant third parties whose Year 2000
compliance could affect Eastern States and has formally inquired about their
Year 2000 status. Eastern States has received responses to 100% of its
inquiries. All respondents have indicated that they will be Year 2000 compliant
by January 1, 2000. Despite its efforts to assure that the third parties are
Year 2000 compliant, Eastern States cannot provide assurance that all
significant third parties will achieve compliance in a timely manner. A third
party's failure to achieve Year 2000 compliance could have a material adverse
effect on Eastern States' operations and cash flow. For example, a third party
might fail to deliver revenue to Eastern States.
Eastern States has prepared contingency plans in the event of potential
problems resulting from failure of Eastern States' or significant third party
computer systems and compressors on January 1, 2000. As part of its contingency
plans, Eastern States will have certain key employees working on both December
31, 1999 and January 1, 2000 to determine that Eastern States' computer systems
and compressors continue to operate normally. Eastern States anticipates minimal
problems will be encountered which would affect trust assets, but the most
reasonably likely worst scenario is the loss of production from 10% to 20% of
the underlying wells for several days in January 2000 due to compressors not
properly functioning. Such loss is estimated to be less than 1% of projected
year 2000 revenue.
NEW ACCOUNTING STANDARDS
We will be required to comply with the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" which must be
adopted for fiscal years beginning after June 15, 2000. SFAS No. 133 requires
that derivatives be reported on the balance sheet at fair value and, if the
derivative is not designated as a hedging instrument, changes in fair value must
be recognized in earnings in the period of change. If the derivative is
designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either offset by the change in fair value
of the hedged asset or liability, if applicable, or reported as a component of
other comprehensive income in the period of change, and subsequently recognized
in earnings when the offsetting hedged transaction occurs. The definition of
derivatives has also been expanded to include contracts that require physical
delivery of oil and gas if the contract allows for net cash settlement. We
primarily use derivatives to hedge product price and interest rate risks. These
derivatives are recorded at cost, and gains and losses on such derivatives are
reported when the hedged transaction occurs. Accordingly, adoption of SFAS No.
133 will have an impact on our reported financial position, and although such
impact has not been determined, it is currently not believed to be material.
Adoption of SFAS No. 133 should have no significant impact on reported earnings,
but could materially affect comprehensive income.
PRODUCTION IMBALANCES
We have only immaterial gas production imbalance positions which result
from the balancing of accounts relating to natural gas volumes on our gathering
systems and third party gathering systems that we utilize.
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<PAGE> 125
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We use derivative financial instruments for hedging purposes, including
swap agreements and commodity futures, swaps, and option agreements. These
financial and commodity-based derivative contracts are used to limit the risks
of natural gas price changes. Gains and losses on these derivatives are entirely
offset by losses and gains on the respective hedged exposures.
Our board of directors has adopted a policy governing the use of derivative
instruments, which requires that all derivatives we use relate to an underlying,
offsetting position, anticipated transaction or firm commitment. The policy
prohibits the use of speculative, highly complex or leveraged derivatives. The
policy also requires review and approval by our president of all risk management
programs using derivatives and all derivative transactions. These programs are
also periodically reviewed by our board of directors.
Hypothetical changes in natural gas prices chosen for the estimated
sensitivity effects are considered to be reasonably possible near-term changes
generally based on consideration of past fluctuations for each risk category. It
is not possible to accurately predict future changes in natural gas prices.
Accordingly, these hypothetical changes may not necessarily be an indicator of
probable future fluctuations.
COMMODITY PRICE RISK
Currently, Eastern States hedges a portion of the market risks associated
with its natural gas sales. During 1998, we entered into gas futures contracts
and gas basis swap agreements to reduce exposure to price volatility in the
physical markets. As of December 31, 1998, outstanding futures contracts had a
fair value gain of $8.4 million and outstanding basis swap agreements had a fair
value gain of $2.8 million. These futures contracts and basis swap agreements
are not recorded on our balance sheet at year end, but are recorded in the month
to which the contracts relate. As of December 31, 1997, outstanding futures
contracts had a fair value loss of $2.0 million and outstanding basis swap
agreements had a fair value gain of $1.2 million.
For commodity derivatives that are permitted to be settled in cash or
another financial instrument, sensitivity effects are as follows. At year-end
1998, the aggregate effect of a hypothetical 10% change in natural gas prices
and basis would result in a $1.1 million change in the fair value of these
financial instruments. This sensitivity does not include the effects of gas
contracts that cannot be settled in cash or with another financial instrument.
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<PAGE> 126
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
Our board of directors consists of five members. Their terms expire at
Eastern States' next annual meeting.
The board of directors elects our executive officers annually and those
executive officers serve at the discretion of the board of directors.
Information concerning our current directors and executive officers is
provided below.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
Johan Nic Vold............................ 52 Chairman of the Board and Director
David A. Dresner.......................... 51 Director
Kristian B. Hausken....................... 47 Director
Jon A. Jacobsen........................... 41 Director
Thor Otto Lohne........................... 42 Director
Clifton A. Brown.......................... 50 President and Chief Executive Officer
Stevens V. Gillespie...................... 42 Senior Vice President and Chief Financial
Officer
James E. Cochran.......................... 38 Senior Vice President -- Operations
Jeffrey E. Fulmer......................... 38 Vice President -- Exploration, Development
and Land
James S. Caballero........................ 45 Vice President -- Engineering,
Acquisitions and Divestitures
Kerry W. Eckstein......................... 43 Vice President, General Counsel and
Secretary
David L. Matz............................. 51 Vice President -- Drilling and Completion
</TABLE>
BACKGROUND OF DIRECTORS AND EXECUTIVE OFFICERS
Johan Nic Vold has served as Executive Vice President of The Statoil Group
since 1988, and has served as Chairman of Statoil Energy's and Eastern States'
Boards of Directors since April 1999.
David A. Dresner has served as President and Chief Executive Officer of
Statoil Energy since June 1996, and as President of Eastern States from 1994
until July 1999. He served as President and Chief Operating Officer for Statoil
Energy and its predecessor from August 1991 through May 1996. Mr. Dresner has
served as a director of Statoil Energy since August 1991 and Eastern States
since 1994.
Kristian B. Hausken has served as Senior Vice President of Strategic
Projects and Restructuring for The Statoil Group since January 1999. From 1993
to 1998, Mr. Hausken served as Senior Vice President of Natural Gas Business
Development of Statoil Energy. He has served as an employee of The Statoil Group
since 1981, and as a Vice President since 1989. He was elected to the Boards of
Directors of Statoil Energy and Eastern States in June 1996.
Jon A. Jacobsen has served as a Senior Vice President of Finance for The
Statoil Group since June 1998 and has served on the Boards of Directors of
Statoil Energy and Eastern States since May 1998. From January 1992 to June
1998, he served with Den Norske Bank (DnB) in positions relating to the energy
and international finance industry, including management of the Asian group
activities for DnB in Singapore.
Thor Otto Lohne has served as the General Manager of the Gas Division of
Statoil (UK) Gas and Chairman of Alliance Gas Limited since August 1996.
Alliance Gas Limited is a marketing subsidiary of The Statoil Group in the
United Kingdom. He joined The Statoil Group in 1983. He was elected to the
Boards of Directors of Statoil Energy and Eastern States in April 1999.
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<PAGE> 127
Clifton A. Brown has been President and Chief Executive Officer of Eastern
States since July 1999. From June 1996 to July 1999, he served as Executive Vice
President of Eastern States. Since June 1996 he has also served as Executive
Vice President of Statoil Energy and Statoil Energy's subsidiaries engaged in
natural gas production and development operations, including Eastern States. He
also served as Senior Vice President of Statoil Energy from January 1994 to June
1996.
Stevens V. Gillespie has served as Senior Vice President and Chief
Financial Officer of Eastern States since July 1999. Since April 1996 he has
also served as Senior Vice President with Statoil Energy and Eastern States,
responsible for management of the company's Producer Services division. From
1984 to 1996, he served as Chief Financial Officer for Statoil Energy and its
predecessor companies.
James E. Cochran has served as Senior Vice President -- Operations of
Statoil Energy and Eastern States since January 1999 and previously served as
Vice President of Eastern States from July 1997 to January 1999. From January
1988 to June 1997, he performed consulting services for various oil and gas
industry clients, including Eastern States. Since June 1984, he has also owned
and operated Big Sandy Oil Company, which conducts natural gas exploration and
production in the Western Pennsylvania region of Appalachian Basin.
Jeffrey E. Fulmer has served as Vice President -- Exploration, Development
and Land of Statoil Energy and Eastern States since July 1996. From 1989 to July
1996, he held the positions of Director -- Exploration, Manager Exploration
Special Projects, and Project Geologist with Statoil Energy and its predecessor
companies.
James S. Caballero has served as Vice President -- Engineering,
Acquisitions and Divestitures of Statoil Energy and Eastern States since 1994.
From 1990 to 1994, he served as Vice President -- of Engineering, Acquisitions
and Divestitures of Statoil Energy's predecessor companies.
Kerry W. Eckstein has served as Vice President, General Counsel and
Secretary to Eastern States since July 1999 and as Counsel to Statoil Energy
since June 1997. From June 1995 to June 1997, he was the owner and operator of
the Thames Group, which conducted investments in oil and gas and other projects.
From 1990 to 1995, he served as Senior Attorney for the international
exploration and production division of Atlantic Richfield Company.
David L. Matz has served as a Vice President -- Drilling and Production
since joining Eastern States' predecessor in 1990.
DIRECTORS' COMPENSATION
All directors are also employees of our affiliates and receive no
additional compensation for service on the board of directors.
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<PAGE> 128
EXECUTIVE COMPENSATION
The table below provides compensation information for our Chief Executive
Officer and the four other most highly compensated executive officers for the
year ended December 31, 1998.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
-------------------------------
SECURITIES
ANNUAL COMPENSATION OTHER UNDERLYING
---------------------- ANNUAL OPTIONS/ ALL OTHER
SALARY($) BONUS($) COMPENSATION($)(2) SARS(#) COMPENSATION($)(3)
---------- --------- ------------------ ---------- ------------------
<S> <C> <C> <C> <C> <C>
Clifton A. Brown(1)........... 251,666 67,953 -- 15,000 5,620
President and Chief
Executive Officer
Stevens V. Gillespie.......... 185,000 36,920 -- 6,200 5,506
Senior Vice President, Chief
Financial Officer and
Treasurer
James Cochran................. 125,000 19,526 -- 5,000 220
Senior Vice President --
Operations
James S. Caballero............ 125,000 20,776 -- 3,300 3,976
Vice
President -- Engineering,
Acquisitions and
Divestitures
Jeffrey E. Fulmer............. 125,000 23,901 -- 3,300 4,098
Vice
President -- Exploration,
Development and Land
</TABLE>
- ---------------
(1) Mr. Dresner served as President of Eastern States at December 31, 1998. He
also serves as President of Statoil Energy and most other U.S. subsidiaries
of The Statoil Group. Effective July 1999, Mr. Dresner resigned as Eastern
States' President. At such date, Clifton A. Brown, who served as Eastern
States' Executive Vice President, was appointed President. During 1998,
approximately 30% of Mr. Dresner's compensation was allocated to Eastern
States.
(2) Amounts do not include perquisites and other personal benefits, securities
or property, because the total amount of such compensation did not exceed
the lesser of $50,000 or 10% of the total of annual salary and bonus
reported for the named executive.
(3) In the case of Messrs. Brown, Gillespie, Caballero and Fulmer, includes a
$5,000, $5,000, $3,594 and $3,751 employee match for Statoil Energy's 401(k)
plan and a $620, $506, $382 and $347 yearly life insurance premium. In the
case of Mr. Cochran, includes a $220 life insurance premium.
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<PAGE> 129
The following table shows information concerning grants of stock options
and stock appreciation rights, or SARs, during 1998 for officers named in the
Summary Compensation Table.
<TABLE>
<CAPTION>
PERCENTAGE POTENTIAL REALIZED
OF TOTAL VALUE AT
NUMBER OF OPTIONS/ ASSUMED
SECURITIES SARS ANNUAL RATE OF
UNDERLYING GRANTED TO STOCK PRICE APPRECIATION
OPTIONS/ EMPLOYEES EXERCISE FOR OPTION TERM(1)
SARS IN PRICE EXPIRATION -------------------------
NAME GRANTED 1998(2) ($/SHARE) DATE 5%($) 10%($)
- ---- ---------- ---------- --------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Clifton A. Brown........... 15,000 7.88% $15.06 8/6/2008 $11,295.00 $22,590.00
Stevens V. Gillespie....... 6,200 3.26% 15.06 8/6/2008 $ 4,668.60 $ 9,337.20
James Cochran.............. 5,000 2.63% 15.06 8/6/2008 $ 3,765.00 $ 7,530.00
James S. Caballero......... 3,300 1.73% 15.06 8/6/2008 $ 2,484.90 $ 4,969.80
Jeffrey E. Fulmer.......... 3,300 1.73% 15.06 8/6/2008 $ 2,484.90 $ 4,969.80
</TABLE>
- ---------------
(1) Based on the fair market value at the date of grant and the stated annual
appreciation rate, compounded annually, for the option term of ten years.
The assumed annual appreciation rates of 5% and 10% were established by the
SEC and therefore are not intended to forecast possible future appreciation,
if any, of the common stock. However, the total potential realized value
shown for the above named executives represents less than 1.5% of the total
appreciation all stockholders would realize.
(2) Based on total options granted by Statoil Energy.
OPTION/SAR GRANTS IN 1998
INDIVIDUAL GRANTS
Options granted under the Statoil Energy Amended and Restated Incentive
Compensation Plan are granted at fair market value at the date of grant and
generally vest over five years and expire ten years after the date of grant.
Shares issued pursuant to option exercise are transfer restricted. See
"-- Employee Shareholders Agreement".
The following table shows information regarding stock options and SARs
exercised during 1998 by the officers named in the Summary Compensation Table
and 1998 year-end values.
AGGREGATED OPTION/SAR EXERCISES IN 1998 AND DECEMBER 31, 1998 OPTION/SAR VALUES
<TABLE>
<CAPTION>
NUMBER OF SHARES VALUE OF
UNDERLYING UNEXERCISED UNEXERCISED IN-THE-MONEY
SHARES OPTIONS/SARS AT OPTIONS/SARS AT
ACQUIRED 12/31/98(#) 12/31/98 ($)
ON VALUE --------------------------- ---------------------------
NAME EXERCISE(#) REALIZED($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- ----------- ----------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Clifton A. Brown....... -- $ -- 32,500 37,500 $112,190 $48,810
Stevens V. Gillespie... -- -- 42,950 13,440 216,942 8,970
James E. Cochran....... -- -- -- 5,000 -- --
James S. Caballero..... 4,000 20,400 4,640 8,610 15,010 11,896
Jeffrey E. Fulmer...... -- -- 3,380 7,820 10,609 9,797
</TABLE>
EMPLOYMENT AND CHANGE IN CONTROL AGREEMENTS
Effective February 1, 1999, Messrs. Brown and Gillespie entered into
individual employment agreements with Statoil Energy pursuant to which they
serve as executive officers. Mr. Brown's agreement has a term of 30 months,
which is automatically extended so that at all times the term is 30 months from
the current date. Mr. Gillespie's agreement has a term of 24 months, which is
automatically extended so that at all times the term is 24 months from the
current date. The employment agreements contain customary non-compete and
non-solicitation provisions which terminate at the later of:
- one year after termination of employment or
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<PAGE> 130
- the end of the period after which the executive continues to receive
severance payments after a change in control.
Mr. Brown's agreement provides for an annual base salary of not less than
$260,000, and Mr. Gillespie's agreement provides for an annual base salary of
not less than $190,000, both of which may be increased at the discretion of the
Board of Directors of Statoil Energy. In addition, Messrs. Brown and Gillespie
are eligible to receive:
- an incentive bonus based on the financial performance of Eastern States
and the evaluation of each of Mr. Brown's and Mr. Gillespie's performance
by the Board of Directors of Statoil Energy;
- stock options awarded at the discretion of Statoil Energy's Board of
Directors consistent with historical practices;
- reimbursement of all reasonable expenses; and
- other benefits including, but not limited to, any retirement benefit
plan, disability, group life, sickness, accident and health insurance
programs provided by Statoil Energy to executives.
Eastern States may terminate either employment agreement at any time
without cause. Messrs. Brown and Gillespie are then entitled to receive "base
compensation" for the longer of one year, or the time period remaining under the
term of the agreement. "Base compensation" is defined as the executive's annual
base salary plus the average of all incentive bonuses paid to the executive
during the previous three years.
Change in Control. Each employment agreement further states that if, within
two years following a change in control (as defined below) the executive is
terminated without cause or terminates his employment for good reason, then the
executive will be entitled to a severance payment in an amount equal to:
- two and one-half times Mr. Brown's base compensation or two times Mr.
Gillespie's base compensation, respectively, plus
- an amount to compensate for lost benefits equal to the lesser of:
-- 10% of the base compensation or
-- $20,000 adjusted for inflation.
In addition, all non-vested stock options will vest automatically upon the
executive's termination within two years of a change in control or a materially
adverse change in the executive's employment and be exercisable until the first
anniversary of the executive's termination of employment with Statoil Energy.
A "change in control" shall be deemed to have occurred if:
- any person other than The Statoil Group, its affiliates or Statoil Energy
or an employee benefit plan of Statoil Energy acquires the beneficial
ownership of any voting security of Statoil Energy and after the
acquisition the acquiring person is the beneficial owner of voting
securities representing more than 50% of the total voting power of all
the outstanding voting securities of Statoil Energy; or
- the stockholders of Statoil Energy, that is, The Statoil Group, approve a
merger, consolidation or reorganization of Eastern States, unless
-- the transaction results in more than 50% of the voting power after the
transaction beneficially owned by holders of voting securities of the
Eastern States prior to the transaction, with substantially the same
voting power or
-- the members of the Eastern States' board of directors prior to the
transaction constitute 50% or more of the members of its board of
directors after the first vote to elect its members following the
transaction; or
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<PAGE> 131
- the stockholders of Eastern States approve a plan of complete
liquidation, dissolution or disposition of substantially all of the
assets or business of Eastern States; or
- Eastern States sells or transfers the business unit or division for which
the employee has primary responsibility to an entity other than The
Statoil Group, Eastern States or an entity controlled by The Statoil
Group or Eastern States and this other entity does not offer the employee
a position with substantially similar responsibilities and duties and the
base compensation and other benefits provided under the employment
agreement.
Upon the sale of Statoil Energy or a "change in control" and a termination
without cause or for good reason, Messrs. Brown and Gillespie would be entitled
to payments in the amount approximating $870,000 and $500,000, respectively.
In the event of termination for cause, the executive will be entitled to no
further compensation or payment.
Messrs. Brown and Gillespie may terminate their employment for good reason.
If the executive resigns for good reason, he is entitled to his base
compensation for the longer of one year or the remainder of the term of the
agreement.
Ninety percent of the compensation owed to Mr. Brown and Mr. Gillespie
under these employment agreements is paid for and allocated to Eastern States.
The remaining 10% is allocated to its affiliate Eastern States Exploration
Company, an indirect wholly owned subsidiary of Statoil Energy, Inc.
SEVERANCE POLICY
In connection with The Statoil Group's intention to sell its ownership
interest in Statoil Energy, Statoil Energy has implemented an employee retention
program, effective as of October 13, 1999, to provide job security for full-time
employees, including Messrs. Cochran, Caballero and Fulmer, of Statoil Energy
and its majority-owned subsidiaries, including Eastern States. The employment
security provisions, which are not applicable to executives with employment
agreements, such as Messrs. Brown and Gillespie, will extend from October 13,
1999 through the first anniversary of the closing of any sale of The Statoil
Group's interest in Statoil Energy.
Severance benefits will only be offered to employees who are involuntarily
terminated "without cause," meaning any employee terminated for failure to
relocate more than fifty miles from his present office, or who voluntarily
leaves his employment "with justification," meaning any employee whose salary is
reduced by at least 10% of his base compensation as of January 1, 2000 or who is
required to relocate to a new location more than fifty miles from his present
office. Each eligible employee must execute, prior to receiving any benefits, a
general release, a confidentiality agreement and a
non-competition/non-solicitation agreement applicable for the period during
which base compensation is extended.
If the above conditions apply, each of Messrs. Cochran, Caballero and
Fulmer will receive a continuation of their base compensation after termination
for a minimum of nine months and a maximum of 12 months. They will also be
entitled to receive a bonus based on the greater of their target bonus for the
year 2000 or the average of their bonuses from the prior two years. Health
benefits will also be extended for the period during which he receives salary
continuation under the retention program. Under this employee retention program,
Messrs. Cochran, Caballero and Fulmer would receive continued base salary, bonus
and benefits approximating $125,000, $150,000 and $160,000, respectively.
AMENDED AND RESTATED INCENTIVE COMPENSATION PLAN
Statoil Energy has an Amended and Restated Incentive Compensation Plan
designed to reward and incentivize employees of Statoil Energy and its
subsidiaries based on the financial performance of Statoil Energy and its
subsidiaries and the personal performance of the employee. Incentives offered
under this plan include:
A-37
<PAGE> 132
- incentive stock options;
- non-qualified stock options;
- stock awards;
- restricted stock awards; and
- performance stock awards.
The Incentive Plan is administered by a committee appointed by Statoil
Energy's board of directors. Only officers and employees of Statoil Energy and
its subsidiaries, including Eastern States, are eligible for such awards. The
maximum aggregate number of shares of common stock which may be issued under the
Incentive Plan is 1,500,000 shares. The Incentive Plan will terminate on January
6, 2002.
Incentive Stock Options. Incentive stock options must satisfy the
requirements of Section 422(b) of the Internal Revenue Code of 1986, as amended.
All incentive stock options must be granted by January 6, 2002 and expire no
later than ten years after the date of grant. The exercise price for each
incentive stock option may not be less than the fair market value of the
underlying common stock. No incentive stock options may be granted to any
employee who, at the time the option is granted, would own more than 10% of the
total combined voting power of all classes of stock unless:
- the exercise price is equal to at least 110% of the fair market value of
the underlying stock; and
- the option is not exercisable after the expiration of five years from the
grant date.
Non-qualified Stock Options. The exercise price of non-qualified stock
options may be determined by the committee, provided that such price is not less
than 33% of the fair market value of the underlying stock on the grant date. The
term of each non-qualified stock option cannot be longer than ten years from the
date of the grant. Each non-qualified stock option will vest and become
exercisable in accordance with the provisions set forth in each stock option
agreement. Notwithstanding any such vesting provisions, any option, whether
incentive or non-qualified, will become fully vested and exercisable as follows:
- when the employee dies, becomes disabled or attains age 65 while employed
by Statoil Energy or one of its subsidiaries; or
- when the employee's employment is terminated within two years following a
change-in-control.
Stock Awards and Restricted Stock Awards. A stock award of common stock is
issued by Statoil Energy to an employee, without other payment therefor, as
additional compensation for his service to Statoil Energy or one of its
subsidiaries. A restricted stock award is common stock issued, without other
payment, but subject to certain restrictions on sale or transfer as determined
by the committee. All employees receiving a restricted stock award must enter
into an escrow agreement with Statoil Energy outlining the conditions of such
award.
Performance Stock Awards. Performance stock awards are contingent rights to
receive shares dependent upon the achievement of certain performance objectives.
Each performance stock award is evidenced by a written agreement outlining the
specific objectives to be achieved. If the employee attains such objectives,
Statoil Energy will issue shares of common stock equal to the number of
performance stock awards granted by the committee to the employee.
Termination of Employment. Any stock option, whether incentive or
non-qualified, held by an employee and not exercised will be immediately
cancelled upon termination of employment by Statoil Energy or one of its
subsidiaries for cause or as a result of voluntary termination by the employee.
If the employee is terminated for any reason other than for cause, any vested
and unexercised option, whether incentive or non-qualified, will continue to be
exercisable in accordance with the terms of its stock option agreement for a
period of ninety days following the notice of termination.
A-38
<PAGE> 133
If the employee is terminated for any reason, any restricted stock award or
performance stock award not already issued and vested will be cancelled
immediately.
EMPLOYEE SHAREHOLDER AGREEMENT
Each employee who receives an incentive under the Incentive Plan is
required to enter into a Shareholders Agreement with Statoil Energy which:
- prohibits the transfer of shares received pursuant to option exercises
and other incentive grants to any person other than another holder who is
an employee at the time of the transfer, the holder's immediate family or
to a Statoil Energy affiliate;
- grants a put option to the holder exercisable during April and October of
each year at fair market value established according to a formula
provided in the agreement; and
- provides for the mandatory repurchase at fair market value upon
termination or death of the employee of all shares owned by the employee
as a result of awards under the Incentive Plan.
If, within one year from the repurchase of common stock as a result of an
employee's termination without cause or resignation for good reason there is:
- an underwritten public offering;
- a merger, consolidation or sale of all or substantially all assets; or
- a transfer of at least 25% of Statoil's capital stock of Statoil Energy,
any of which results in a change in control, then,
Statoil Energy will pay to the employee the difference between the value of a
share sold in such transaction and the price at which Statoil Energy repurchased
the employee's shares.
SECURITY OWNERSHIP OF MANAGEMENT AND CERTAIN BENEFICIAL OWNERS
Eastern States is a privately held company. All of the outstanding shares
of common stock of Eastern States are owned by Statoil Energy Holdings, Inc., a
wholly owned subsidiary of Statoil Energy.
A-39
<PAGE> 134
INDEX TO FINANCIAL STATEMENTS
EASTERN STATES OIL & GAS, INC.
<TABLE>
<S> <C>
EASTERN STATES OIL & GAS, INC.
Consolidated Financial Statements
Report of Independent Auditors......................... AF-2
Consolidated Balance Sheets as of December 31, 1997 and
1998.................................................. AF-3
Consolidated Statements of Operations for the years
ended December 31, 1996, 1997 and 1998................ AF-4
Consolidated Statements of Stockholder's Equity........ AF-5
Consolidated Statements of Cash Flows for the years
ended December 31, 1996, 1997 and 1998................ AF-6
Notes to Consolidated Financial Statements............. AF-7
Unaudited Consolidated Financial Statements
Unaudited Consolidated Balance Sheets as of December
31, 1998 and June 30, 1999............................ AF-18
Unaudited Consolidated Statements of Operations for the
six month periods ended June 30, 1998 and 1999........ AF-19
Unaudited Consolidated Statements of Cash Flows for the
six month periods ended June 30, 1998 and 1999........ AF-20
Notes to Unaudited Consolidated Financial Statements... AF-21
Unaudited Pro Forma Consolidated Financial Statements
Unaudited Pro Forma Consolidated Balance Sheet as of
June 30, 1999......................................... AF-23
Unaudited Pro Forma Consolidated Statement of
Operations for the year ended December 31, 1998....... AF-24
Unaudited Pro Forma Consolidated Statement of
Operations for the six months ended June 30, 1999..... AF-25
Notes to Unaudited Pro Forma Consolidated Financial
Statements............................................ AF-26
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
Report of Independent Auditors............................ AF-28
Consolidated Income Statement for the fiscal year ended
September 30, 1996..................................... AF-29
Consolidated Statement of Cash Flows for the year ended
September 30, 1996..................................... AF-30
Notes to Consolidated Financial Statements................ AF-31
Unaudited Domestic Operations of Blazer Energy Corp. and
Subsidiary
Unaudited Consolidated Income Statement for the nine
months ended June 30, 1997............................ AF-39
Unaudited Consolidated Statement of Cash Flows for the
nine months ended June 30, 1997....................... AF-40
Notes to Unaudited Consolidated Financial Statements... AF-41
</TABLE>
AF-1
<PAGE> 135
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.
We have audited the accompanying consolidated balance sheets of Eastern
States Oil & Gas, Inc. as of December 31, 1997 and 1998, and the related
consolidated statements of operations, stockholder's equity and cash flows for
each of the three years in the period ended December 31, 1998. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Eastern States
Oil & Gas, Inc. at December 31, 1997 and 1998, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles.
ERNST & YOUNG LLP
Vienna, Virginia
August 23, 1999, except for Note 12, as
to which the date is October 13, 1999
AF-2
<PAGE> 136
EASTERN STATES OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1997 1998
-------- --------
<S> <C> <C>
Current assets
Accounts receivable -- related party...................... $ 21,795 $ 28,787
Accounts receivable -- trade, net......................... 3,928 7,732
Inventories............................................... 4,112 1,600
Prepaid expenses and other................................ 41 159
-------- --------
Total current assets.............................. 29,876 38,278
-------- --------
Property and equipment, net
Natural gas and oil properties -- full cost method (See
Note 3)................................................ 543,777 559,523
Gathering systems......................................... 46,112 56,088
Other property and equipment.............................. 3,496 4,196
-------- --------
Total property and equipment...................... 593,385 619,807
-------- --------
Deferred income taxes....................................... 2,880 --
Other assets................................................ 198 248
-------- --------
Total assets...................................... $626,339 $658,333
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable.......................................... $ 17,389 $ 21,214
Accrued expenses.......................................... 1,691 1,136
Accrued severance and property taxes...................... 739 2,713
-------- --------
Total current liabilities......................... 19,819 25,063
-------- --------
Deferred income taxes....................................... -- 926
Long-term debt.............................................. 503,588 505,488
Intercompany liabilities.................................... 37,834 51,974
Other liabilities........................................... 363 1,801
Stockholder's equity
Common stock ($1 par value, 1,000 shares authorized,
issued and
outstanding)........................................... 1 1
Additional paid-in capital................................ 51,500 51,500
Retained earnings......................................... 13,234 21,580
-------- --------
Total stockholder's equity........................ 64,735 73,081
-------- --------
Total liabilities and stockholder's equity........ $626,339 $658,333
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-3
<PAGE> 137
EASTERN STATES OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1996 1997 1998
------- ------- --------
<S> <C> <C> <C>
Revenue
Natural gas and oil....................................... $18,247 $64,604 $ 95,315
Tax credit monetization................................... -- 764 9,355
------- ------- --------
18,247 65,368 104,670
------- ------- --------
Costs and expenses
Direct operating costs.................................... 2,655 13,454 15,950
Selling, general and administrative....................... 1,630 3,254 5,462
Depreciation, depletion and amortization.................. 4,783 19,073 31,517
------- ------- --------
9,068 35,781 52,929
------- ------- --------
Income from operations...................................... 9,179 29,587 51,741
Interest expense............................................ 4,338 21,608 38,952
------- ------- --------
Income before income taxes.................................. 4,841 7,979 12,789
Income tax expense (benefit)................................ 956 (1,171) 4,443
------- ------- --------
Net income.................................................. $ 3,885 $ 9,150 $ 8,346
======= ======= ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-4
<PAGE> 138
EASTERN STATES OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED
STOCK CAPITAL EARNINGS TOTAL
------ ---------- -------- -------
<S> <C> <C> <C> <C>
Balance, December 31, 1995............................ $1 $ 1,500 $ 199 $ 1,700
Net income -- 1996.................................... 3,885 3,885
-- ------- ------- -------
Balance, December 31, 1996............................ 1 1,500 4,084 5,585
Net income -- 1997.................................... 9,150 9,150
Contribution of capital............................... 50,000 50,000
-- ------- ------- -------
Balance, December 31, 1997............................ 1 51,500 13,234 64,735
Net income -- 1998.................................... 8,346 8,346
-- ------- ------- -------
Balance, December 31, 1998............................ $1 $51,500 $21,580 $73,081
== ======= ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-5
<PAGE> 139
EASTERN STATES OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
-------- --------- --------
<S> <C> <C> <C>
Cash flows from operating activities
Net income................................................ $ 3,885 $ 9,150 $ 8,346
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion and amortization............... 4,783 19,073 31,517
Deferred income tax expense (benefit).................. 909 (3,788) 3,806
Net changes in working capital
Accounts receivable.................................... (2,398) (22,960) (10,796)
Inventories............................................ (52) (3,920) 2,512
Prepaid expenses and other............................. (18) (12) (118)
Accounts payable and accrued expenses.................. 3,192 14,701 5,244
-------- --------- --------
Net cash provided by operating activities................... 10,301 12,244 40,511
-------- --------- --------
Cash flows from investing activities
Acquisition of natural gas and oil properties............. (31,760) (450,214) (6,812)
Other additions to natural gas and oil properties......... (24,511) (143,596) (74,030)
Disposition of natural gas and oil properties............. -- 82,300 23,957
Other property additions.................................. (518) (3,197) (1,683)
Other..................................................... 218 (102) 2,017
-------- --------- --------
Net cash used in investing activities....................... (56,571) (514,809) (56,551)
-------- --------- --------
Cash flows from financing activities
Contribution of capital................................... -- 50,000 --
Issuance of long-term debt................................ 28,267 433,955 1,900
Intercompany activity..................................... 18,003 18,610 14,140
-------- --------- --------
Net cash provided by financing activities................... 46,270 502,565 16,040
-------- --------- --------
Net change in cash and cash equivalents..................... -- -- --
Cash and cash equivalents
Beginning of year......................................... -- -- --
-------- --------- --------
End of the year........................................... $ -- $ -- $ --
======== ========= ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-6
<PAGE> 140
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company
Eastern States Oil & Gas, Inc. ("Company") is a wholly-owned subsidiary of
Statoil Energy Holdings, Inc. ("SEH") and is engaged in natural gas and oil
exploration and production in the states of Ohio, West Virginia and Kentucky.
SEH is a wholly-owned subsidiary of Statoil Energy, Inc. ("STEN") and holds
STEN's interests in various operating entities engaged in energy related
activities.
Principles of consolidation
The consolidated financial statements include the accounts of the Company,
its wholly-owned subsidiaries and its proportionate share of the assets,
liabilities, revenue and expenses of various oil and gas development ventures.
All intercompany accounts and transactions have been eliminated.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect certain reported amounts of assets and liabilities and
disclosure of contingent liabilities at the date of the financial statements.
These estimates and assumptions also affect certain amounts of reported revenues
and expenses. Actual results could differ from those estimates.
Derivatives
The Company uses derivatives to hedge product price risks, as opposed to
their use for trading purposes. Gains and losses on commodity futures contracts
and other price risk management instruments are recognized in oil and gas
revenues when the hedged transaction occurs. Cash flows related to derivative
transactions are included in operating activities. In order to qualify for hedge
accounting, the derivative instrument must be designated and effective as a
hedge. If the derivative does not meet these requirements, the derivative
instrument is marked-to-market in income. In the event the hedged item matures,
is sold, or is terminated, the realized and unrealized gains and losses are
recognized in income coincidental with the transaction.
Accounts receivable
Accounts receivable arises primarily from the sale of natural gas. The
Company performs ongoing credit evaluations of its customers to minimize its
exposure to credit risk. The Company's allowance for doubtful accounts, which is
reflected in the consolidated balance sheets as a reduction in accounts
receivable, was $1.0 million and $0.2 million at December 31, 1997 and 1998,
respectively.
Concentration of credit risk
In 1996, 1997 and 1998, sales to Statoil Energy Services, Inc. ("SES"), an
affiliated company, were 85%, 83% and 59%, respectively, of total revenues.
Sales to an unaffiliated purchaser were 23% in 1998. There were no other
customers with purchases of greater than 10% of total revenues for 1996, 1997
and 1998.
Inventories
Inventories, consisting primarily of operating supplies and other materials
used in well drilling, are stated at the lower of cost or market using the
first-in, first-out method.
AF-7
<PAGE> 141
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Property and equipment
In accounting for natural gas and oil exploration and development costs,
the Company follows the full cost method of accounting, under which all
productive and nonproductive costs associated with acquisition, exploration and
development activities are capitalized. This includes internal staff costs that
are directly associated with acquisition, exploration and development activities
but does not include any costs related to production or similar activities.
Internal costs include Company staff time related to the acquisition,
exploration and development of natural gas and oil properties and are
capitalized on the basis of periodic time studies.
Natural gas and oil properties at December 31, 1998 include costs of $39.4
million of acquisition costs and $1.1 million of exploration costs associated
with unevaluated properties. These costs were incurred in 1997 and are excluded
from capitalized costs being amortized, pending determination of the existence
of proved reserves. Depreciation, depletion and amortization of evaluated costs
is provided using the units-of-production method based on proved natural gas and
oil reserves. Estimated restoration and abandonment costs, net of salvage
credits, are taken into account in determining depreciation and depletion.
Capitalized costs may not exceed the present value of future net revenues from
production of proved natural gas and oil reserves, determined in accordance with
procedures prescribed by the Securities and Exchange Commission. When an oil and
gas property ceases economic production, the Company either sells the property
or dismantles and removes all surface equipment, plugs the wells, and restores
the property's surface in accordance with various regulations and agreements
before abandoning the property. The Company accrues the estimated future costs,
net of estimated equipment salvage values, over the property's estimated
productive life. At December 31, 1998, the Company had accrued $1.8 million for
such costs. Anticipated costs for currently proved properties that we expect to
plug and abandon total $22.4 million, primarily payable over the next 50 years.
Gathering systems are depreciated using the straight-line method over the
useful lives of assets (20 to 25 years).
Other property and equipment is stated at original cost and long-lived
assets are reviewed annually in accordance with current accounting standards.
Depreciation of other property and equipment is provided on a straight-line
basis over the useful lives of the assets (5 to 10 years for equipment). Repairs
of property and equipment are charged to expense as incurred.
Accounts payable
Accounts payable includes credit balances to the extent that checks issued
have not been presented to the Company's bank for payment. These credit balances
included in accounts payable were approximately $2.9 million and $5.2 million at
December 31, 1997 and 1998, respectively.
Revenue recognition
The Company records its natural gas and oil revenues on the entitlement
method whereby the Company recognizes revenues based upon its entitled share of
production. As of December 31, 1996, 1997, and 1998, the Company's natural gas
and oil imbalances were not material.
Natural gas measurement
The Company records estimated amounts for natural gas revenues and natural
gas purchase costs based on volumetric calculations under its natural gas sales
and purchase contracts. Variances resulting from such calculations are inherent
in natural gas sales, production, operation, measurement and administration.
Management does not believe that differences between actual and estimated
natural gas revenues are material.
AF-8
<PAGE> 142
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income taxes
The Company follows the asset and liability method of accounting for income
taxes. Deferred tax assets and liabilities are determined using the tax rate for
the period in which those amounts are expected to be received or paid, based on
temporary differences between the tax bases of assets and liabilities and their
reported amounts. Under this method, the effect of a change in income tax rates
on deferred tax assets and liabilities is recognized as an element of income in
the period the rate change is enacted.
Since 1997, the Company and all Statoil affiliated companies located in the
United States, participate in a tax sharing arrangement, whereby all required
federal income tax returns for 1997 and future years will be filed on a
consolidated basis. For financial reporting purposes, each company accounts for
its income taxes on a separate company basis. Any benefits or detriments
resulting from the consolidation of federal income tax returns will remain with
or be incurred by the holding company, Statoil North America, Inc. ("SNA").
Segment reporting
In accordance with Statement of Financial Accounting Standards No. 131
("SFAS 131"), Disclosures about Segments of an Enterprise and Related
Information, the Company has identified only one operating segment, which is the
exploration and production of oil and gas. All the Company's assets are located
in the United States and all of its revenues are attributable to United States
customers.
2. ACQUISITIONS AND DISPOSALS
The following acquisitions have been accounted for using the purchase
method. The results of the acquired operations are included in the accompanying
consolidated financial statements from their respective dates of acquisition:
Purchases of natural gas and oil properties from unaffiliated parties,
recorded at cost exclusive of internal cost capitalization, are as follows (in
millions):
<TABLE>
<CAPTION>
PROVED UNPROVED GATHERING OTHER
RESERVES PROPERTIES SYSTEMS PROPERTY TOTAL
-------- ---------- --------- -------- ------
<S> <C> <C> <C> <C> <C>
1996................................... $ 31.6 $ 0.2 $ 5.8 $ 0.3 $ 37.9
1997................................... 409.9 40.3 31.7 8.4 490.3
1998................................... 0.8 6.0 -- -- 6.8
</TABLE>
In 1997, the Company acquired the stock of Blazer Energy Corporation
(Blazer), a wholly-owned subsidiary of Ashland Inc. for a purchase price of
$567.1 million. Blazer is engaged in the exploration, development, production,
acquisition and marketing of natural gas and oil. Subsequent to the closing of
the transaction, Blazer properties located in the Gulf of Mexico region were
sold to an affiliated company, Statoil Exploration, Inc. ("SEUS"), a
wholly-owned subsidiary of SNA for $82.3 million. In addition, in 1998, the
Company sold certain proved developed reserves along with undeveloped acreage in
approximately 400 non-producing properties for $24.0 million.
AF-9
<PAGE> 143
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. PROPERTY AND EQUIPMENT
Investments in property and equipment are comprised of the following (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1997 1998
-------- --------
<S> <C> <C>
Natural gas and oil properties
Proved.................................................... $523,506 $567,741
Unproved.................................................. 44,066 42,444
-------- --------
Total cost............................................. 567,572 610,185
Accumulated depletion.................................. (23,795) (50,662)
-------- --------
Net book value of natural gas and oil properties............ 543,777 559,523
-------- --------
Gathering systems
Cost...................................................... 47,931 60,507
Accumulated depletion..................................... (1,819) (4,419)
-------- --------
Net book value of gathering systems......................... 46,112 56,088
-------- --------
Other property and equipment
Cost...................................................... 4,036 5,718
Accumulated depreciation and amortization................. (540) (1,522)
-------- --------
Net book value of other property and equipment.............. 3,496 4,196
-------- --------
Net book value of property and equipment.................... $593,385 $619,807
======== ========
</TABLE>
4. PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
It is the Company's general practice to hedge commodity price risk arising
from its unmatched firm physical commitments to purchase or sell hydrocarbon
products at fixed prices by taking offsetting positions in futures, options and
swaps (collectively, "derivative commodity instruments"). The maturity of these
derivative commodity instruments is matched closely with the underlying physical
commitment. The Company does not hold or issue derivative financial instruments
for speculative or trading purposes.
The Company is exposed to credit risk in the event of non-performance by
counterparts on natural gas forwards, options and swaps. The Company does not
anticipate non-performance by any of these counterparts. The amount of such
exposure is generally the unrealized gain on such contracts.
At December 31, the estimated pre-tax fair values determined by market
quotes, of the Company's derivative commodity instruments were as follows (in
millions):
<TABLE>
<CAPTION>
1997 1998
---------------- -----------------
NOTIONAL FAIR NOTIONAL FAIR
VALUE VALUE VALUE VALUE
-------- ----- -------- ------
<S> <C> <C> <C> <C>
Futures............................................ $36.7 $38.2 $ 8.2 $ 10.0
Swaps.............................................. 58.1 57.2 130.3 137.7
Basis.............................................. 4.4 5.6 10.6 13.4
Options............................................ 71.6 69.0 51.4 50.6
</TABLE>
The Company recognized a $1.2 million loss, a $4.5 million loss and a $7.1
million gain in 1996, 1997 and 1998, respectively, related to its derivative
commodity instruments. Such amounts are reflected as a component of natural gas
and oil revenue.
The carrying value of the Company's accounts receivable, accounts payable
and long-term debt approximate fair value.
AF-10
<PAGE> 144
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on the
balance sheet as either an asset or liability measured at its fair value. SFAS
133 requires that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement. SFAS 133 is
effective for fiscal years beginning after June 15, 2000. The Company has not
determined the method or quantified the effects of adopting SFAS 133 on its
financial statements; however, the Company will adopt SFAS 133 effective January
1, 2001.
In November 1998, the Financial Accounting Standards Board Emerging Issues
Task Force (EITF) issued "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" (EITF No. 98-10). The EITF provides guidance
regarding the accounting for energy trading contracts which should be applied to
financial statements issued for fiscal years beginning after December 15, 1998.
The application of EITF 98-10 will not have a significant impact on the
Company's financial statements.
5. LONG-TERM DEBT
In August 1999, the Company and SEH agreed to aggregate and extend to
December 31, 2001 the final repayment dates of various notes payable to SEH
aggregating $505.5 million. This note has an 8% annual rate of interest, payable
semi-annually on January 1 and July 1 each year.
During the years ended December 31, 1996, 1997 and 1998, the Company
recorded interest expense due to SEH of $4.8 million, $23.2 million and $40.9
million. All amounts were settled as of the respective year end dates. Interest
expense, in the amount of $0.5 million, $1.5 million and $1.9 million, relating
to unevaluated natural gas and oil properties, has been capitalized as part of
natural gas and oil properties in 1996, 1997 and 1998, respectively.
6. INCOME TAXES
The provision for income taxes is as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1996 1997 1998
---- ------- ------
<S> <C> <C> <C>
Current tax expense
Federal................................................... $ -- $ 1,570 $ --
State..................................................... 47 1,047 637
---- ------- ------
Total current tax expense................................... 47 2,617 637
---- ------- ------
Deferred tax expense (benefit)
Federal................................................... 779 (3,246) 3,261
State..................................................... 130 (542) 545
---- ------- ------
Total deferred tax expense (benefit)........................ 909 (3,788) 3,806
---- ------- ------
Total income tax expense (benefit).......................... $956 $(1,171) $4,443
==== ======= ======
</TABLE>
AF-11
<PAGE> 145
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Deferred tax liabilities (assets) are comprised of the following (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1997 1998
------- --------
<S> <C> <C>
Deferred tax liabilities
Excess of book basis over tax basis:
Natural gas and oil properties......................... $ 4,317 $ 12,709
------- --------
Total deferred tax liabilities.............................. 4,317 12,709
------- --------
Deferred tax assets
Net operating loss carryforwards.......................... -- (10,181)
Minimum tax credit carryforwards.......................... (1,570) (1,570)
Other..................................................... (5,627) (32)
------- --------
Total deferred tax assets................................... (7,197) (11,783)
------- --------
Net deferred income tax liability (asset)................... $(2,880) $ 926
======= ========
</TABLE>
The provision for income taxes differs from the amount of income tax
determined by applying the applicable statutory federal income tax rate to
pre-tax income as a result of the following (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1996 1997 1998
------ ------- -------
<S> <C> <C> <C>
Federal income tax....................................... $1,694 $ 2,793 $ 4,476
Change in valuation allowance............................ (47) -- --
Permanent items.......................................... 1 13 17
Transfer pricing adjustment.............................. (870) (2,249) (1,232)
State and local income taxes............................. 178 505 1,182
Nonconventional fuel source tax credits.................. -- (2,233) --
------ ------- -------
Total income tax expense (benefit)....................... $ 956 $(1,171) $ 4,443
====== ======= =======
</TABLE>
As of December 31, 1998, the Company has available, for income tax
purposes, minimum tax credit carryforwards of approximately $1.5 million, which
do not expire, and net operating loss carryforwards of approximately $25.0
million, which expire in 2006 through 2018. For the years ended December 31,
1996, 1997 and 1998, the Company made income tax payments of $0.1 million, $2.6
million and $0.6 million, respectively.
7. STOCK OPTIONS
Key employees of the Company participate in a STEN sponsored incentive
compensation plan under which stock options may be granted. Each option granted
to an employee entitles the grantee to purchase one share of STEN common stock
at a price equal to its fair market value at the date of the grant. All options
generally vest over five years and expire ten years after the date of grant or
90 days after
AF-12
<PAGE> 146
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
termination of employment, whichever is earlier. Transactions involving stock
options under the plan are summarized below:
<TABLE>
<CAPTION>
INCENTIVE NON-
STOCK QUALIFIED OPTION PRICE
OPTIONS OPTIONS TOTAL PER SHARE
--------- --------- ------- ----------------
<S> <C> <C> <C> <C>
Outstanding at December 31, 1995................ 86,500 -- 86,500 $9.15 to $13.80
Granted....................................... 29,500 -- 29,500 $10.75
Canceled...................................... -- -- --
Exercised..................................... -- -- --
------- ------ -------
Outstanding at December 31, 1996................ 116,000 -- 116,000 $9.15 to $13.80
Granted....................................... -- 33,500 33,500 $14.92
Canceled...................................... -- -- --
Exercised..................................... (5,110) -- (5,110) $9.15
------- ------ -------
Outstanding at December 31, 1997................ 110,890 33,500 144,390 $9.15 to $14.92
Granted....................................... -- 44,350 44,350 $15.06
Canceled...................................... -- -- --
Exercised..................................... (4,000) -- (4,000) $9.15 to $10.05
------- ------ -------
Outstanding at December 31, 1998................ 106,890 77,850 184,740 $9.15 to $15.06
======= ====== =======
</TABLE>
<TABLE>
<CAPTION>
WEIGHTED AVERAGE
PRICE PER SHARE
----------------
<S> <C> <C> <C> <C>
Exercisable at December 31, 1996................ 64,600 -- 64,600 $10.33
======= =======
Exercisable at December 31, 1997................ 75,090 -- 75,090 $10.49
======= =======
Exercisable at December 31, 1998................ 86,690 6,700 93,390 $10.87
======= ====== =======
</TABLE>
Management has reviewed SFAS 123, "Accounting for Stock-Based
Compensation", which outlines a fair value based method of accounting for stock
options or similar equity instruments and has elected to continue using the
intrinsic value based method of accounting, as prescribed by Accounting
Principles Board Opinion No. 25. Accordingly, no compensation expense has been
recorded in the accompanying financial statements.
Net income would be $3.8 million in 1996, $9.1 million in 1997 and $8.3
million in 1998 had the Company adopted the fair value based accounting model
set forth in SFAS 123. Under the fair value based method, the weighted average
fair values of options granted during 1996, 1997 and 1998 were $2.88, $4.00 and
$4.04, respectively. The fair value of stock options were calculated using the
minimum value method with the following weighted average assumptions for grants
in 1996, 1997 and 1998: risk free interest rate of 6.25%; no expected dividend
yield; and an expected option life of five years. The fair value of stock
options included in the pro forma results for 1996, 1997 and 1998 are not
necessarily indicative of future effects on net income.
8. RELATED PARTY TRANSACTIONS
Accounts receivable with related party consists of accrued natural gas
sales to SES.
AF-13
<PAGE> 147
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Intercompany liabilities consist of the following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1997 1998
-------- --------
<S> <C> <C>
STEN........................................................ $(14,858) $(81,773)
SES, receivable in 1998..................................... (7,502) 39,580
ESEC........................................................ (15,474) (9,781)
-------- --------
$(37,834) $(51,974)
======== ========
</TABLE>
The intercompany activity with STEN consists of amounts due for
payroll-related costs, fixed asset additions, corporate taxes, interest payments
to SEH on behalf of the Company and other cash transactions to and from STEN.
The intercompany activity with SES relates to marketing of natural gas to SES
and fees for risk management services provided to the Company. Eastern States
Exploration Company ("ESEC") is a wholly-owned subsidiary of SEH engaged in
natural gas and oil exploration and production in Pennsylvania. The intercompany
payable to ESEC consists primarily of amounts due for drilling expenditures,
certain operating costs and other transactions related to cash management
activities.
See Note 5 for debt and interest transactions between the Company and SEH.
9. PROFIT SHARING PLAN
Substantially all full-time employees of the Company participate in a STEN
sponsored profit sharing plan that includes an employee savings feature under
Section 401(k) of the Internal Revenue Code. Participants can elect to defer up
to 15% of their total compensation through contributions to the plan and STEN
matches 50% of employee contributions up to 6% of an employee's total
compensation. Effective January 1, 1997, the vesting schedule for STEN's
contributions was shortened from seven to five years.
For the years ended December 31, 1996, 1997 and 1998, charges to income for
the Company's share of contributions to the plan aggregated $0.02 million, $0.10
million, and $0.20 million, respectively. STEN also made supplemental
contributions, a portion of which benefited Company participants, for the years
ended December 31, 1996 and 1997 in the amounts of $0.15 million and $0.30
million, respectively.
10. COMMITMENTS AND CONTINGENT LIABILITIES
The Company leases facilities and operating equipment from third parties
under operating lease arrangements, certain of which contain renewal or purchase
options. Total charges to income for rent expense aggregated $0.4 million in
1996, $0.9 million in 1997 and $1.8 million in 1998.
Future minimum lease commitments under operating leases in each of the five
years subsequent to December 31, 1998 are $1.1 million in 1999, $1.0 million in
2000, $0.9 million in 2001, $0.8 million in 2002, $0.8 million in 2003 and $3.0
million thereafter.
The Company has employment agreements with two of its executive officers
that provide for severance payments and accelerated vesting of options upon
termination of employment under certain circumstances. The Company's maximum
contingent obligation for severance payments under these agreements in such
event was approximately $1.4 million at December 31, 1998.
The Company is involved in various legal actions and claims arising in the
normal course of business. Based upon its current assessment of the facts, and
the law, management does not believe that the outcome of any such action or
claim will have a material adverse effect upon the consolidated financial
position or results of operations of the Company. However, these actions against
the Company are subject to the uncertainties inherent in any litigation.
AF-14
<PAGE> 148
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. MONETIZATION OF SECTION 29 TAX CREDITS
In 1997, the Company entered into a transaction with a financial
institution under which it monetized $43 million of future Section 29 credits
related to its working interests in approximately 1,500 gross wells. In
consideration, the Company received a production payment and a note which
entitles it to all of the cash flow from the properties until approximately 95%
of the expected, pre-tax net present value of the presently projected future
production from the properties has been received, which is expected to occur in
the year 2018. In addition to the note and production payment, the Company
received a fixed cash payment at closing of $7.9 million (recorded as a
reduction to the book value of oil and gas properties) and will receive
quarterly payments equal to a specified percentage of the Section 29 tax credits
generated from the properties through 2002. The Company also retained a
reversionary interest in the properties pursuant to which 100% of the interests
in the properties transferred will revert to the Company when 100% of currently
projected future production from the properties has been realized.
Based on current law, Section 29 tax credits will be available until
December 31, 2002. The Company has the option to repurchase the properties after
December 31, 2002 at the fair market value of the properties at the time of
repurchase less the value of the outstanding note and production payment and the
value of the reversionary interest. The Company has also entered into a
management services agreement with the buyer pursuant to which the Company will
manage and operate the properties on behalf of the buyer.
12. SUBSEQUENT EVENT
On October 13, 1999, The Statoil Group -- Norway ("Statoil") announced
plans to seek a buyer for its U.S. natural gas and electric power production and
marketing unit, Statoil Energy, Inc. ("STEN") in connection with a corporate
restructuring process. The Statoil Group has announced its intentions to market
STEN as an integrated enterprise consisting of STEN's subsidiaries, including
Eastern States, involved in gas production, power production, energy marketing
and energy trading. However, the Statoil Group may determine that the sale of
individual assets or divisions, including Eastern States, is more appropriate.
If such a sale of Statoil Energy or Eastern States occurs, no assurance can be
given that it will not adversely affect the Company. In addition, an employee
retention program has been implemented which will extend through the first
anniversary of the sale date.
13. RESERVE INFORMATION (UNAUDITED)
Costs incurred in the Company's natural gas and oil operations, including
internal capitalization allocations, were as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1996 1997 1998
------- -------- -------
<S> <C> <C> <C>
Exploration............................................ $ 1,956 $ 3,932 $ 2,772
Development............................................ 13,535 22,743 69,667
Acquisitions
Natural gas and oil properties....................... 33,115 534,198 8,403
Gathering systems.................................... 7,665 32,937 --
Production costs, net of service fees.................. 2,414 6,866 10,089
------- -------- -------
$58,685 $600,676 $90,931
======= ======== =======
</TABLE>
Depreciation, depletion and amortization relating to natural gas and oil
operations for the years ended December 31, 1996, 1997, and 1998 was $4.7
million, $18.9 million, and $30.6 million, respectively. Internal costs
capitalized for the years ended December 31, 1996, 1997 and 1998 were $3.0
million, $7.1 million and $14.9 million, respectively.
AF-15
<PAGE> 149
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
The following tables set forth information with respect to the Company's
estimated proved natural gas and oil reserves, all of which are located in the
continental United States. The information has been reviewed by Ryder Scott
Company, L.P., an independent petroleum engineering firm, as of December 31,
1998.
The table of proved natural gas and oil reserves represents estimated
quantities of natural gas, oil and natural gas liquids which geological and
engineering data demonstrate to be recoverable in future years from known
reservoirs under existing economic and operating conditions. The proved reserves
are further classified as developed and undeveloped. The reserves described
below and the related standardized measures of discounted net cash flows are
estimates only and do not purport to reflect realizable values or fair market
values of the Company's reserves. The Company emphasizes that reserve estimates
are inherently imprecise. Substantial revisions to existing reserve estimates
occur periodically due to additional production history from each well,
current-year drilling activity and other new geologic or reserve characteristic
information that may be discovered each year.
The Company's estimates of proved developed and undeveloped reserves of
natural gas (99% in 1998) and oil (1% in 1998) expressed in millions of cubic
feet equivalents (MMcfe) as of December 31, 1996, 1997, 1998, and the change in
its proved reserves are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
------- --------- ---------
<S> <C> <C> <C>
Proved developed and undeveloped reserves
Beginning of year.................................. 82,656 176,673 1,025,315
Production......................................... (6,825) (24,192) (38,514)
Revisions of previous estimates.................... 5,801 (5,521) 150
Acquisitions of reserves in place.................. 64,732 913,104 1,293
Disposition of reserves in place................... (5,336) (51,144) (22,356)
Extensions, discoveries and other revisions........ 35,645 16,395 95,850
------- --------- ---------
End of year........................................ 176,673 1,025,315 1,061,738
======= ========= =========
Proved developed reserves at end of year............. 129,749 715,664 709,305
======= ========= =========
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows (in thousands)
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------
1996 1997 1998
--------- ---------- ----------
<S> <C> <C> <C>
Future cash flows................................ $ 649,856 $2,670,246 $2,901,515
Future development costs......................... (28,428) (175,215) (195,499)
Future production costs.......................... (125,680) (554,171) (548,361)
Future income tax expense........................ (155,599) (547,697) (632,829)
--------- ---------- ----------
Future net cash flows............................ 340,149 1,393,163 1,524,826
Discount at 10% per annum for timing of cash
flows.......................................... (203,974) (873,454) (986,425)
--------- ---------- ----------
Discounted future net cash flows................. $ 136,175 $ 519,709 $ 538,401
========= ========== ==========
</TABLE>
AF-16
<PAGE> 150
EASTERN STATES OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1997 1998
-------- --------- --------
<S> <C> <C> <C>
Balance, beginning of year.......................... $ 52,071 $ 136,175 $519,709
Sales, net of production costs...................... (16,337) (60,528) (77,983)
Extensions and discoveries, net of production
costs............................................. 47,708 13,162 72,593
Acquisitions of developed reserves in place......... 56,958 466,177 928
Acquisitions of undeveloped reserves in place....... -- 157,903 --
Disposition of reserves in place.................... (5,672) (32,184) (24,826)
Change in sales prices, net of production costs..... 27,458 (68,043) 14,319
Changes in estimated future development costs....... (27) 3,731 (11,761)
Previously estimated development cost incurred
during the year................................... 4,500 7,410 17,617
Revisions of quantity estimates..................... (3,318) (3,376) 4,923
Accretion of discount............................... 6,331 18,333 64,406
Change in income taxes.............................. (36,975) (109,351) 6,388
Changes in production rates and other............... 3,478 (9,700) (47,912)
-------- --------- --------
Balance, end of year................................ $136,175 $ 519,709 $538,401
======== ========= ========
</TABLE>
The standardized measure of discounted future net cash flows (discounted at
10%) relating to proved natural gas and oil reserves is prescribed by SFAS
Statement No. 69, "Disclosures About Oil and Gas Producing Activities." The
statement requires measurement of future net cash flows through assignment of a
monetary value to proved reserve quantities and changes therein using a
standardized formula. The amounts shown above were developed as follows:
1. An estimate was made of the quantity of proved reserves and the
future periods in which they are expected to be produced based on
year-end economic conditions.
2. Year-end prices in effect for each respective year were applied to
the estimated quantities of year-end reserves. Prices remained
constant, except in instances where fixed and determinable gas
price escalations are provided by contracts. The average prices
used at December 31, 1996, 1997, and 1998 were $3.68, $2.57, and
$2.71 per Mcf of natural gas and $22.50, $15.00, and $9.00 per
barrel of oil, respectively.
3. The future gross cash inflows were reduced by estimated future
costs of developing and producing the proved reserves and the
estimated effect of future income taxes. The principal sources of
changes in the standardized measure of future net cash flows are
described above.
AF-17
<PAGE> 151
EASTERN STATES OIL & GAS, INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
1998 1999
------------ -----------
(AUDITED) (UNAUDITED)
<S> <C> <C>
Current assets
Accounts receivable -- related party...................... $ 28,787 $ 17,048
Accounts receivable -- trade, net......................... 7,732 7,298
Inventories............................................... 1,600 1,633
Prepaid expenses and other................................ 159 143
-------- --------
Total current assets.............................. 38,278 26,122
-------- --------
Property and equipment, net
Natural gas and oil properties (full cost method)......... 559,523 563,767
Gathering systems......................................... 56,088 57,106
Other property and equipment.............................. 4,196 4,428
-------- --------
Total property and equipment...................... 619,807 625,301
-------- --------
Other assets................................................ 248 444
-------- --------
Total assets...................................... $658,333 $651,867
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable.......................................... $ 21,214 $ 9,579
Accrued expenses.......................................... 1,136 991
Accrued severance and property taxes...................... 2,713 2,140
-------- --------
Total current liabilities......................... 25,063 12,710
-------- --------
Deferred income taxes....................................... 926 3,766
Long-term debt.............................................. 505,488 505,488
Intercompany liabilities.................................... 51,974 48,217
Other liabilities........................................... 1,801 2,559
Stockholder's equity
Common stock ($1 par value, 1,000 shares authorized,
issued and outstanding)................................ 1 1
Additional paid-in capital................................ 51,500 51,500
Retained earnings......................................... 21,580 27,626
-------- --------
Total stockholder's equity........................ 73,081 79,127
-------- --------
Total liabilities and stockholder's equity........ $658,333 $651,867
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-18
<PAGE> 152
EASTERN STATES OIL & GAS, INC.
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-----------------
1998 1999
------- -------
<S> <C> <C>
Revenue
Natural gas and oil....................................... $50,034 $53,149
Tax credit monetization................................... 4,643 4,574
------- -------
54,677 57,723
------- -------
Costs and expenses
Direct operating costs.................................... 7,927 8,043
Selling, general and administrative....................... 2,249 2,868
Depreciation, depletion and amortization.................. 16,520 16,129
------- -------
26,696 27,040
------- -------
Income from operations...................................... 27,981 30,683
Interest expense............................................ 19,513 21,265
------- -------
Income before income taxes.................................. 8,468 9,418
Income tax expense.......................................... 3,112 3,372
------- -------
Net income.................................................. $ 5,356 $ 6,046
======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-19
<PAGE> 153
EASTERN STATES OIL & GAS, INC.
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-------------------
1998 1999
-------- --------
<S> <C> <C>
Cash flows from operating activities
Net income................................................ $ 5,356 $ 6,046
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion and amortization............... 16,520 16,129
Deferred income tax expense............................ 2,857 2,840
Net changes in working capital
Accounts receivable.................................... 4,943 12,173
Inventories............................................ 820 (33)
Prepaid expenses and other............................. (29) 16
Accounts payable and accrued expenses.................. (8,386) (12,353)
-------- --------
Net cash provided by operating activities................... 22,081 24,818
-------- --------
Cash flows from investing activities
Acquisition of natural gas and oil properties............. (1,695) (140)
Other additions to natural gas and oil properties......... (22,207) (21,458)
Disposition of natural gas and oil properties............. 23,673 --
Other..................................................... (277) 537
-------- --------
Net cash used in investing activities....................... (506) (21,061)
-------- --------
Cash flows from financing activities
Issuance of long-term debt................................ 1,900 --
Intercompany activity..................................... (23,475) (3,757)
-------- --------
Net cash used in financing activities....................... (21,575) (3,757)
-------- --------
Net change in cash and cash equivalents..................... -- --
Cash and cash equivalents
Beginning of year......................................... -- --
-------- --------
End of the year........................................... $ -- $ --
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-20
<PAGE> 154
EASTERN STATES OIL & GAS, INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. FINANCIAL STATEMENT PRESENTATION
Eastern States Oil & Gas, Inc ("Company") is a wholly-owned subsidiary of
Statoil Energy Holding, Inc. ("SEH") and is engaged in natural gas and oil
exploration and production in the states of Ohio, West Virginia and Kentucky.
SEH is a wholly-owned subsidiary of Statoil Energy, Inc. ("STEN") and holds
STEN's interests in various operating entities engaged in energy related
activities.
The accompanying condensed consolidated financial statements of the Company
have been prepared in accordance with generally accepted accounting principles
for interim financial information and with the instructions for Article 10 of
Regulation S-X. The consolidated balance sheet as of June 30, 1999, the
consolidated statements of operations for the six months ended June 30, 1998 and
1999 and the consolidated statements of cash flows for the six month periods
ended June 30, 1998 and 1999 are unaudited but include all adjustments
(consisting of only normal recurring adjustments) which the Company considers
necessary for a fair presentation of the financial position at such dates and
the operating results and cash flows for those periods. Although the Company
believes that the disclosures in the accompanying consolidated financial
statements are adequate to make the information presented not misleading,
certain information normally included in financial statements and related
footnotes prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to the rules and regulations of the
Securities and Exchange Commission. The December 31, 1998 consolidated balance
sheet data included herein were derived from audited consolidated financial
statements but do not include all disclosures required by generally accepted
accounting principles. The accompanying financial statements should be read in
conjunction with the consolidated financial statements for the year ended
December 31, 1998 and related footnotes as contained within this Form S-1.
The unaudited consolidated financial statements include the accounts of the
Company, its wholly-owned subsidiaries and its proportionate share of the
assets, liabilities, revenue and expenses of various oil and gas development
ventures. All intercompany accounts and transactions have been eliminated.
2. SUBSEQUENT EVENT
On October 13, 1999, The Statoil Group -- Norway ("Statoil") announced
plans to seek a buyer for its U.S. natural gas and electric power production and
marketing unit, Statoil Energy, Inc. ("STEN") in connection with a corporate
restructuring process. The Statoil Group has announced its intentions to market
STEN as an integrated enterprise consisting of STEN's subsidiaries, including
Eastern States, involved in gas production, power production, energy marketing
and energy trading. However, the Statoil Group may determine that the sale of
individual assets or divisions, including Eastern States, is more appropriate.
If such a sale of Statoil Energy or Eastern States occurs, no assurance can be
given that it will not adversely affect the Company.
AF-21
<PAGE> 155
EASTERN STATES OIL & GAS, INC.
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
The accompanying Unaudited Pro Forma Consolidated Financial Statements of
Eastern States Oil & Gas, Inc. ("the Company") have been prepared by recording
pro forma adjustments to the historical consolidated financial statements of the
Company. The Unaudited Pro Forma Consolidated Balance Sheet as of June 30, 1999
has been prepared as if the Trust Offering, as described in Note 2, was
consummated on June 30, 1999. The Unaudited Pro Forma Consolidated Statements of
Operations for the year ended December 31, 1998 and for the six months ended
June 30, 1999 have been prepared as if the Trust Offering was consummated
immediately prior to January 1, 1998 and January 1, 1999, respectively.
The Unaudited Pro Forma Consolidated Financial Statements are not
necessarily indicative of the financial position or results of operations which
would have occurred had the transactions occurred on the assumed dates.
Additionally, future results may vary significantly from the results reflected
in the Unaudited Pro Forma Consolidated Statements of Operations due to normal
production declines, changes in prices, future transactions and other factors.
These statements should be read in conjunction with the Company's audited
consolidated financial statements and the related notes for the year ended
December 31, 1998, included in this prospectus.
AF-22
<PAGE> 156
EASTERN STATES OIL & GAS, INC.
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
JUNE 30, 1999
ASSETS
<TABLE>
<CAPTION>
PRO FORMA ADJUSTMENTS (NOTE 3)
-------------------------------------
TRUST TOTAL
HISTORICAL OFFERING (A) PRO FORMA
---------- ------------ ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Current assets
Accounts receivable -- related party...................... $ 17,048 $ 17,048
Accounts receivable -- trade, net......................... 7,298 7,298
Inventories............................................... 1,633 1,633
Prepaid expenses and other................................ 143 143
-------- --------- --------
Total current assets.............................. 26,122 26,122
-------- --------- --------
Property and equipment, net
Natural gas & oil properties (full cost method)........... 563,767 $(127,911) 435,856
Gathering systems......................................... 57,106 57,106
Other property and equipment.............................. 4,428 4,428
-------- --------- --------
Total property and equipment...................... 625,301 (127,911) 497,390
-------- --------- --------
Other assets................................................ 444 444
-------- --------- --------
Total assets...................................... $651,867 $(127,911) $523,956
======== ========= ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable.......................................... $ 9,579 $ 9,579
Accrued expenses.......................................... 991 991
Accrued severance & property taxes........................ 2,140 2,140
-------- --------- --------
Total current liabilities......................... 12,710 12,710
-------- --------- --------
Deferred income taxes....................................... 3,766 3,766
Long-term debt.............................................. 505,488 $(127,911) 377,577
Intercompany liabilities.................................... 48,217 48,217
Other liabilities........................................... 2,559 2,559
Stockholder's equity
Common stock ($1 par value, 1,000 shares authorized, issued
and outstanding).......................................... 1 1
Additional paid-in capital.................................. 51,500 51,500
Retained earnings........................................... 27,626 27,626
-------- --------- --------
Total stockholder's equity........................ 79,127 79,127
-------- --------- --------
Total liabilities and stockholder's equity........ $651,867 $(127,911) $523,956
======== ========= ========
</TABLE>
See accompanying notes to pro forma consolidated financial statements.
AF-23
<PAGE> 157
EASTERN STATES OIL & GAS, INC.
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
PRO FORMA ADJUSTMENTS (NOTE 3)
-------------------------------------
TRUST TOTAL
HISTORICAL OFFERING (B) PRO FORMA
---------- ------------ ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Revenue
Natural gas and oil....................................... $ 95,315 $(25,246) $70,069
Tax credit monetization................................... 9,355 9,355
-------- -------- -------
104,670 (25,246) 79,424
-------- -------- -------
Costs and expenses
Direct operating costs.................................... 15,950 (5,171) 10,779
Selling, general and administrative....................... 5,462 (1,653) 3,809
Depreciation, depletion and amortization.................. 31,517 (8,560) 22,957
-------- -------- -------
52,929 (15,384) 37,545
-------- -------- -------
Income from operations...................................... 51,741 (9,862) 41,879
Interest expense............................................ 38,952 (10,233) 28,719
-------- -------- -------
Income before income taxes.................................. 12,789 371 13,160
Income tax expense.......................................... 4,443 151 4,594
-------- -------- -------
Net income.................................................. $ 8,346 $ 220 $ 8,566
======== ======== =======
</TABLE>
See accompanying notes to pro forma consolidated financial statements.
AF-24
<PAGE> 158
EASTERN STATES OIL & GAS, INC.
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 1999
<TABLE>
<CAPTION>
PRO FORMA ADJUSTMENTS (NOTE 3)
-------------------------------------
TRUST TOTAL
HISTORICAL OFFERING (B) PRO FORMA
---------- ------------ ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Revenue
Natural gas and oil....................................... $53,149 $(10,824) $42,325
Tax credit monetization................................... 4,574 4,574
------- -------- -------
57,723 (10,824) 46,899
------- -------- -------
Costs and expenses
Direct operating costs.................................... 8,043 (2,586) 5,457
Selling, general and administrative....................... 2,868 (826) 2,042
Depreciation, depletion and amortization.................. 16,129 (4,006) 12,123
------- -------- -------
27,040 (7,418) 19,622
------- -------- -------
Income from operations...................................... 30,683 (3,406) 27,277
Interest expense............................................ 21,265 (5,116) 16,149
------- -------- -------
Income before income taxes.................................. 9,418 1,710 11,128
Income tax expense.......................................... 3,372 699 4,071
------- -------- -------
Net income.................................................. $ 6,046 $ 1,011 $ 7,057
======= ======== =======
</TABLE>
See accompanying notes to pro forma consolidated financial statements.
AF-25
<PAGE> 159
EASTERN STATES OIL & GAS, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The accompanying Unaudited Pro Forma Consolidated Balance Sheet at June 30,
1999 has been prepared assuming Eastern States Oil & Gas, Inc. ("the Company")
consummated the sale of 75% of the Appalachian Natural Gas Trust (formerly the
Appalachian Basin Royalty Trust) units to the public ("Trust Offering") on June
30, 1999 (Note 2). The Unaudited Pro Forma Consolidated Statements of Operations
for the year ended December 31, 1998 and the six months ended June 30, 1999 have
been prepared assuming the Company consummated the Trust Offering immediately
prior to January 1, 1998 and January 1, 1999, respectively. The Unaudited Pro
Forma Consolidated Statements of Operations are not necessarily indicative of
the results of operations had the above-described transactions occurred on the
assumed dates.
2. APPALACHIAN NATURAL GAS TRUST OFFERING
The Company formed the Appalachian Natural Gas Trust in August 1999. The
Company plans to sell 7,875,000, or 75%, of the Appalachian Natural Gas Trust
units to the public in October or November 1999. An additional 11.25%, or
1,181,250 units, may be sold pursuant to exercise of the underwriters'
overallotment option. The offering price to the public will be $20.00 per Trust
unit.
3. PRO FORMA ADJUSTMENTS
Pro Forma adjustments necessary to adjust the Consolidated Balance Sheet
and Statements of Operations are as follows:
(a) To record net proceeds of $127,911,000 received by the Company upon
consummation of the Trust Offering, reflecting the sale of 7,875,000
Appalachian Natural Gas Trust units by the Company to the public at a
price of $20.00 per unit, less underwriters' discount, hedging effects
and estimated expenses. This transaction has been reflected as a
reduction of natural gas and oil properties, as it has an immaterial
impact on the Company's depletion rate. All proceeds from the offering
will be used to repay debt to a related party.
(b) To record reduction of revenue and expenses related to the sale of
Appalachian Natural Gas Trust units, assuming the underwriters'
overallotment option is not exercised (Note 2), the reduction in
interest expense attributable to a decrease in long-term debt upon
application of net proceeds of $127,911,000 from the Trust Offering
(Note 3(a)) and the related change in income taxes at the Company's
effective tax rate of 40.85%. Interest expense was determined using the
interest rate of 8% incurred by the Company under its long-term note
payable.
4. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Estimated Quantities of Pro Forma Proved Oil and Gas Reserves
Pro forma reserve estimates at June 30, 1999 are based on reports
prepared by management for proved reserves of the Company, using June 30,
1999 prices and costs.
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which, based on geologic and engineering data, are
estimated to be reasonably recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved
developed reserves are those which are expected to be recovered through
existing wells with existing equipment and operating methods. Because of
inherent uncertainties and the limited nature of reservoir data, such
estimates are subject to change, as additional information becomes
available.
AF-26
<PAGE> 160
Pro Forma Proved Oil and Gas reserves at June 30, 1999
<TABLE>
<CAPTION>
OIL (BBLS) GAS (MMCF)
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Proved reserves............................................. 1,859 806,693
===== =======
Proved developed reserves................................... 1,827 480,270
===== =======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to pro
Forma Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows ("Standardized
Measure") is prepared using assumptions required by the Financial Accounting
Standards Board. Such assumptions include the use of year-end prices for oil and
gas and year-end costs for estimated future development and production
expenditures to produce year-end estimated proved reserves. Discounted future
net cash flows are calculated using a 10% rate.
The Standardized Measure does not represent the Company's estimate of
future net cash flows or the value of proved oil and gas reserves. Probable and
possible reserves, which may become proved in the future, are excluded from the
calculations. Furthermore, year-end prices, used to determine the standardized
measure of discounted cash flows, are influenced by seasonal demand other
factors and may not be the most representative in estimating future revenues or
reserve data.
Pro Forma Standardized Measure of Discounted Future Net Cash Flows (in
thousands) at:
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
1998 1999
------------ ----------
<S> <C> <C>
Future cash flows........................................... $2,273,567 $1,979,654
Future production costs..................................... (423,922) (398,211)
Future development costs.................................... (181,308) (180,535)
---------- ----------
Future net cash inflows before income tax................... 1,668,337 1,400,908
Future income tax expense................................... (489,314) (258,286)
---------- ----------
Future net cash flows....................................... 1,179,023 1,142,622
Discount at 10% per annum for timing of cash flows.......... (761,617) (784,108)
---------- ----------
Discounted future net cash flows............................ $ 417,406 $ 358,514
========== ==========
</TABLE>
AF-27
<PAGE> 161
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholder
Eastern States Oil & Gas, Inc.
We have audited the accompanying consolidated income statement and cash
flows for the domestic operations of Blazer Energy Corp. and subsidiary
(formerly Ashland Exploration, Inc.) for the year ended September 30, 1996.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated results of domestic operations and
cash flows for Blazer Energy Corp. and subsidiary for the year ended September
30, 1996, in conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Vienna, Virginia
August 23, 1999
AF-28
<PAGE> 162
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
CONSOLIDATED INCOME STATEMENT
YEAR ENDED SEPTEMBER 30, 1996
(IN THOUSANDS)
<TABLE>
<S> <C>
Revenues:
Sales and operating revenues:
Natural gas............................................ $ 94,750
Crude oil.............................................. 3,759
Columbia Gas settlement (Note 5).......................... 73,139
Other (Note 6)............................................ 1,671
--------
173,319
--------
Cost and expenses:
Operating expenses........................................ 32,642
NORM reclamation/litigation (Note 3)...................... 3,049
Depreciation, depletion and amortization (Note 1)......... 28,921
General and administrative expenses (Note 7).............. 15,658
Exploration costs, including dry holes.................... 11,204
--------
91,474
--------
Operating income............................................ 81,845
Interest expense............................................ 195
--------
Income before income taxes.................................. 81,650
Income tax expense (Note 2)................................. 19,132
--------
Net income.................................................. $ 62,518
========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-29
<PAGE> 163
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED SEPTEMBER 30, 1996
(IN THOUSANDS)
<TABLE>
<S> <C>
Cash flows from operating activities
Net income................................................ $ 62,518
Adjustments to reconcile income to net cash provided by
operating activities:
Depreciation, depletion and amortization............... 28,921
Impairment of undeveloped leaseholds................... 2,128
Deferred income taxes.................................. 4,438
Changes in operating assets and liabilities:
Accounts receivable.................................... (4,288)
Inventories............................................ 300
Prepaids and other current assets...................... (766)
Trade accounts payable................................. 25,840
Accrued liabilities.................................... 2,438
Other.................................................. (1,961)
--------
Net cash provided by operating activities................... 119,568
--------
Cash flows from investing activities
Property, plant and equipment:
Additions.............................................. (45,091)
Property disposals..................................... 2,149
--------
Net cash used in investing activities....................... (42,942)
--------
Increase in net obligations with affiliated Companies....... $ 76,626
========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-30
<PAGE> 164
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1996
1. SIGNIFICANT ACCOUNTING POLICIES
Background
Blazer Energy Corp. and subsidiary (formerly Ashland Exploration, Inc.)
("Company") operated both domestic and international exploration and production
activities. Immediately prior to the acquisition of the Company by a subsidiary
of Statoil Energy, Inc. (see Note 10), Ashland Inc. (parent company of Blazer
Energy Corp.) removed all international exploration and production operations of
the Company. The accompanying financial statements reflect all domestic
exploration and production operations. The Company is engaged in the exploration
for and the development, production, acquisition and marketing of natural gas
and oil in the United States.
Consolidation
The financial statements include the domestic accounts of Blazer Energy
Corp. and subsidiary. Significant intercompany accounts and transactions have
been eliminated in consolidation. Consistent with industry practice, the Company
utilizes pro rata consolidation to account for its investment in oil and gas
ventures.
Risk and uncertainties
The preparation of the Company's consolidated financial statements in
conformity with generally accepted accounting principles requires the Company's
management to make estimates and assumptions that affect the reported amounts of
revenues and expenses. Actual results could differ from the estimates and
assumptions used.
Inventories
Crude oil inventories are stated at current market value. Materials and
supplies inventories are stated at the lower of cost or market.
Property, plant and equipment
The successful efforts method of accounting is followed for costs incurred
in oil and gas exploration and development activities. Property acquisition
costs and exploratory drilling costs for oil and gas properties are initially
capitalized. If and when exploratory wells are determined to be nonproductive,
the related costs are charged to expense. Other exploration costs, including
geological, geophysical and lease rentals, are charged to expense as incurred.
When a property is determined to contain proved reserves, property
acquisition costs and related exploratory drilling costs are transferred to
producing properties. Depreciation, depletion and amortization of producing
properties are computed separately on a field basis using the
units-of-production method.
Significant unproved properties are periodically evaluated and provision
made for impairment individually. Insignificant properties are amortized to
provide for estimated impairment.
Environmental Costs
Accruals for environmental costs are recognized when it is probable that a
liability has been incurred and the amount of that liability can be reasonably
estimated. Such costs are charged to expense if they are related to the
remediation of conditions caused by past operations, or are not expected to
mitigate or prevent contamination from future operations. Accruals are recorded
at undiscounted amounts based on
AF-31
<PAGE> 165
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
experience, assessments and current technology and are regularly adjusted as
environmental assessments and remediation efforts proceed.
Natural Gas Revenues
Natural gas revenues generally are recorded using the sales method, whereby
the Company recognizes natural gas revenues based on the amount of gas sold to
purchasers on its behalf. As of September 30, 1996, the Company did not have any
material gas imbalances.
Crude Oil Revenues
Crude oil revenue is recognized as produced.
Dismantlement, Removal and Restoration Costs
The estimated costs, net of salvage values, of dismantling and removing
major facilities, including necessary site restoration, are accrued using the
units-of-production method. In the case of facilities where such costs are not
expected to be significant, the net cost is accrued when operations cease.
Income Taxes
The consolidated domestic provision was computed on the basis of a separate
return.
Hedging Activities
The Company selectively uses futures contracts and swaps to reduce price
volatility and lock in favorable sales prices for future production of natural
gas and crude oil. Gains and losses on futures contracts and swaps are deferred
until the related gas or oil production has been produced or delivered. As a
result, gains and losses are generally offset by similar changes in the price of
natural gas and crude oil. While these instruments are intended to reduce the
Company's exposure to declines in the market price of natural gas and crude oil,
they may also limit the Company's gain from increases in the market price of
natural gas and crude oil.
The futures contracts have settlement guaranteed by the New York Mercantile
Exchange ("NYMEX") and have nominal credit risk. The swap agreements are with
third parties and expose the Company to credit risk to the extent the third
parties are unable to meet their monthly settlement commitment to the Company.
2. INCOME TAXES
A summary of the provision for income tax expense follows:
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30,
1996
--------------
(IN THOUSANDS)
<S> <C>
Current tax expense.................................... $14,694
Deferred tax expense................................... 4,438
-------
$19,132
=======
</TABLE>
AF-32
<PAGE> 166
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The difference between the statutory rate and the Company's effective
income tax rate is reconciled as follows:
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30,
1996
--------------
(IN THOUSANDS)
<S> <C>
Income tax computed at statutory rates................. $28,578
Section 29 tax credits................................. (10,509)
Adjustment to prior year's tax......................... 537
State tax, net of federal tax.......................... 137
Other.................................................. 389
-------
$19,132
=======
</TABLE>
3. COMMITMENTS AND CONTINGENCIES
The Company is subject to various federal, state and local environmental
laws and regulations, which require remediation efforts at multiple locations,
including operating facilities and previously owned or operated facilities.
Environmental reserves are subject to considerable uncertainties that affect the
Company's ability to estimate its share of the ultimate costs of required
remediation efforts. Such uncertainties involve the nature and extent of
contamination at each site, the extent of required cleanup efforts under
existing environmental regulations, widely varying costs of alternate cleanup
methods, changes in environmental regulations, the potential effect of
continuing improvements in remediation technology and the number and financial
strength of other potentially responsible parties at multiparty sites. As a
result, charges to income for environmental liabilities could have a material
effect on results of operations in a particular quarter or fiscal year as
assessments and remediation efforts proceed, revised estimates are made based on
current information or as new remediation sites are identified.
During 1996, the U.S. Environmental Protection Agency and the state of
Kentucky approved the Company's plan of reclamation (including disposal off
site) of naturally occurring radioactive material ("NORM") from the Martha oil
field in Kentucky. The Company's independent contractor began implementing the
NORM reclamation work in September 1996.
In addition to environmental matters, the Company is party to numerous
claims and lawsuits. While these actions are being contested, the outcome of
individual matters is not predictable with assurance. Although any actual
liability is not determinable as of September 30, 1996, the Company believes
that any liability resulting from these matters, after taking into consideration
Ashland's insurance coverages should not have a material adverse effect on the
Company's consolidated financial position.
4. EMPLOYEES' PENSION AND RETIREMENT BENEFITS
Ashland sponsors pension plans that cover substantially all employees,
other than union employees covered by multiemployer pension plans under
collective bargaining agreements. Benefits under Ashland's plans generally are
based on employees' years of service and compensation during the years
immediately preceding their retirement. For certain plans, such benefits are
expected to come in part from one-half of employees' leveraged employee stock
ownership plan ("LESOP") accounts. Ashland determines the level of contributions
to the pension plans annually and contributes amounts within allowable
limitations imposed by Internal Revenue Service regulations. Ashland contributed
the maximum tax-deductible contributions to its pension plans during the last
three years. A discount rate of 8% and an assumed rate of salary increases of 5%
were used in determining the actuarial present value of projected benefit
obligations at September 30, 1996. The Company's expense related to pension and
the LESOP amounted to $1,512,000 in 1996.
AF-33
<PAGE> 167
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. COLUMBIA GAS SETTLEMENT
During 1995, the Company entered into a settlement agreement with Columbia
Gas Transmission ("Columbia") to resolve claims involving natural gas sales
contracts that were abrogated by Columbia in 1991. The agreement provided for a
$78,500,000 payment to the Company, of which 5% was withheld by Columbia to be
used to potentially satisfy the claims of nonsettling producers. The Company
received the proceeds net of expenses under this agreement in 1996, which
resulted in operating income of $73,139,000. In the event that any portion of
the amount withheld by Columbia is not used to satisfy such nonsettling claims,
the Company and Ashland have agreed that such amount will be paid to Ashland.
6. OTHER REVENUES
The Company purchases third-party natural gas for resale and delivery into
major interstate pipelines. Revenue from these purchases and resales were
$500,000 in 1996.
7. RELATED PARTY TRANSACTIONS
The Company sells natural gas production to Ashland Petroleum Company, a
wholly owned subsidiary of Ashland. Sales to Ashland Petroleum Company were
$2,700,000 for the fiscal year ending 1996.
Certain administrative services are provided to the Company by Ashland. For
these services, the Company receives an allocation of Ashland's general and
administrative expenses which amounted to $2,326,000 in 1996. These services
include, among others, insurance administration and certain tax and legal
administrative activities. It is Ashland's policy to charge these expenses and
all other central administrative costs on the basis of direct usage when
identifiable. Management of the Company has determined that this method is
reasonable.
8. LEASES AND OTHER COMMITMENTS
The Company is a lessee in noncancelable leasing agreements for office
buildings and other equipment and properties which expire at various dates.
Rental expense under operating leases was $5,900,000 in 1996. Future minimum
rental payments (which escalate over time) at September 30, 1996 follow (in
thousands):
<TABLE>
<S> <C>
1997....................................................... $1,004
1998....................................................... 950
1999....................................................... 944
2000....................................................... 1,072
2001....................................................... 1,048
Thereafter................................................. 3,104
</TABLE>
9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and
Gas Reserves
The following tables summarize discounted future net cash flows and changes
in such flows in accordance with Statement of Financial Accounting Standards
Board No. 69, ("SFAS 69"), Disclosures About Oil and Gas Producing Activities.
Under the guidelines of SFAS 69, estimated future cash flows are determined
based on current prices for crude oil and natural gas, estimated production of
proved crude oil and natural gas reserves, estimated future production and
development costs of those reserves based on current costs and economic
conditions and estimated future income taxes based on taxing arrangements in
effect at year-end which include allocation of the full tax benefit of Section
29 tax credits. Such cash flows are then discounted using the prescribed 10%
rate.
AF-34
<PAGE> 168
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) -- (CONTINUED)
Many other assumptions could have been made which may have resulted in
significantly different estimates. The Company does not rely upon these
estimates in making investment and operating decisions. Furthermore, the Company
does not represent that such estimates are indicative of its expected future
cash flows or the current value of its reserves. Since gas prices utilized in
deriving these estimates are based on conditions that existed at September 30
and are usually different than prices that exist at December 31 due to seasonal
fluctuations in the natural gas market, the estimates may not be comparable to
those of other companies with different fiscal years. Prices can also vary
significantly at the same point in time from year to year due to a variety of
factors. The average gas price used in the discounted future net cash flows
calculations was based on $1.85 per MMBtu for 1996.
Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
SEPTEMBER 30,
1996
-------------
(IN MILLIONS)
<S> <C>
Future cash inflows.................................... $1,273
Future production (lifting) costs...................... (509)
Future development costs............................... (55)
Future income taxes.................................... (116)
------
593
Annual 10% discount.................................... (304)
------
Standardized measure of discounted future net cash
flows................................................ $ 289
======
</TABLE>
] Changes in Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30,
1996
-------------
(IN MILLIONS)
<S> <C>
Net change due to extensions and discoveries............ $ 27
Sales of oil and gas produced -- net of
production (lifting) costs............................ (85)
Changes in prices....................................... 60
Previously estimated development costs incurred......... 22
Net change due to revisions of previous estimates of
reserves.............................................. 4
Purchase (net of sales) of reserves in place............ 1
Accretion of 10% discount............................... 25
Other -- net(1)......................................... 10
Net change in income taxes.............................. (27)
----
37
Discounted future net cash flows at beginning of year... 252
----
Discounted future net cash flows at end of year......... $289
====
</TABLE>
- ---------------
(1) Includes changes in future production and development costs and changes in
the timing of future production.
AF-35
<PAGE> 169
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) -- (CONTINUED)
Crude Oil and Natural Gas Reserves, Revenues and Costs
The following tables summarize the Company's crude oil and natural gas
reserves. Crude oil and natural gas reserves are reported net of royalties and
interests owned by others.
Reserves reported in the table are estimated and are subject to future
revisions. Since October 1, 1995, no estimates of the Company's total proved net
oil or gas reserves have been filed or included in reports to any federal
authority or agency other than the Securities and Exchange Commission (the
"Commission"). Crude oil reserves of 1.6 MMBbls at September 30, 1996 are as
estimated by Netherland Sewell.
Crude Oil and Natural Gas Reserves
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30,
1996
-------------
<S> <C>
Crude Oil Reserves (Mmbbls)
Proved developed and undeveloped reserves:
Beginning of year.................................... 1.3
Revisions of previous estimates...................... 0.4
Extensions and discoveries........................... --
Production........................................... (0.2)
Net purchases of reserves in place................... 0.1
----
End of year.......................................... 1.6
====
Proved developed reserves at beginning of year......... 1.3
Proved developed reserves at end of year............... 1.6
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED
SEPTEMBER 30,
1996
-------------
<S> <C>
Natural Gas Reserves (BCF)
Proved developed and undeveloped reserves:
Beginning of year.................................... 507.4
Revisions of previous estimates...................... 37.6
Extensions and discoveries........................... 70.0
Production........................................... (39.7)
Purchase (net of sales) of reserves in place......... 1.6
-----
End of year.......................................... 576.9
=====
Proved developed reserves at beginning of year......... 427.3
Proved developed reserves at end of year............... 477.0
</TABLE>
Net Oil and Gas Production
The following table summarizes net oil and gas production (net after
royalty) for the fiscal year ended September 30, 1996.
<TABLE>
<CAPTION>
1996
----
<S> <C>
Net natural gas production (MMcf per day)................... 109
Net crude oil production (Bbls per day)..................... 564
</TABLE>
AF-36
<PAGE> 170
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) -- (CONTINUED)
Average Sales Price and Production Cost
The Company's average sales price per unit and production cost per unit for
crude oil and natural gas for the fiscal year ended September 30, 1996 is set
forth in the table below.
<TABLE>
<CAPTION>
1996
------
<S> <C>
Average sales prices -- natural gas (per Mcf)............... $ 2.39
Average sales prices -- crude oil (per Bbl)................. $18.22
Average production cost (per Mcfe)(1)....................... $ 0.47
</TABLE>
- ---------------
(1) Equivalents computed on a six Mcf to one Bbl ratio.
Gross and Net Productive Wells
The following table sets forth the Company's gross and net productive
wells.
<TABLE>
<CAPTION>
SEPTEMBER 30,
1996
-------------
GROSS NET
----- -----
<S> <C> <C>
Productive wells -- Gas............................... 4,211 3,836
Productive wells -- Oil............................... 36 22
</TABLE>
These wells include 317 gross wells and 279 net wells at September 30,
1996, which have multiple completions.
Total Gross and Net Oil and Gas Producing and Undeveloped Acreage
The Company's major interests consist of producing and nonproducing working
interests located in the Appalachian and Gulf Coast areas, as well as royalty
interests located primarily in the Southwest and Midcontinent areas of the
United States. The following table sets forth the Company's total gross and net
oil and gas producing and undeveloped acreage:
<TABLE>
<CAPTION>
GROSS NET GROSS NET
PRODUCING PRODUCING UNDEVELOPED UNDEVELOPED
ACREAGE ACREAGE ACREAGE ACREAGE
- --------- --------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
1,263 936 748 410
</TABLE>
Net Productive and Dry Wells Drilled
The Company's net productive and dry wells drilled during the fiscal year
ended September 30, 1996 are set forth below.
<TABLE>
<CAPTION>
1996
----
<S> <C>
Net exploratory wells drilled
Net productive wells...................................... 1
Net dry wells............................................. 1
----
Total............................................. 2
====
Net development wells drilled:
Net productive wells...................................... 79
Net dry wells............................................. --
</TABLE>
AF-37
<PAGE> 171
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. SUBSEQUENT EVENT
On July 1, 1997, a subsidiary of Statoil Energy, Inc. ("STEN") entered into
a Stock Purchase Agreement to acquire the domestic operations of Blazer Energy
Corp. for a purchase price of $567.1 million. Items excluded from this
transaction include the Martha Oil Field in Kentucky, including related
environmental obligations, insurance policies, office facilities and leases,
certain fee interests in land and any potential additional recovery related to
the Columbia Gas settlement (See Note 5). Pursuant to this agreement, Ashland
agreed to indemnify STEN from and against losses resulting from certain other
environmental claims and litigation.
AF-38
<PAGE> 172
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
UNAUDITED CONSOLIDATED INCOME STATEMENT
NINE MONTHS ENDED JUNE 30, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
(UNAUDITED)
-----------
<S> <C>
Revenues:
Sales and operating revenues
Natural gas............................................ $90,850
Crude oil.............................................. 2,699
Other..................................................... 1,499
-------
95,048
-------
Cost and expenses:
Operating expenses........................................ 26,771
NORM reclamation/litigation (Note 2)...................... 7,525
Depreciation, depletion and amortization.................. 27,999
General and administrative expenses....................... 11,341
Exploration costs, including dry holes.................... 3,850
-------
77,486
-------
Operating income............................................ 17,562
Interest expense............................................ 139
-------
Income before income taxes.................................. 17,423
Income tax benefit (Note 3)................................. (413)
-------
Net income.................................................. $17,836
=======
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-39
<PAGE> 173
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE NINE MONTHS ENDED JUNE 30, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
(UNAUDITED)
-----------
<S> <C>
Cash flows from operating activities
Net income................................................ $ 17,836
Adjustments to reconcile income to net cash provided by
operating activities:
Depreciation, depletion and amortization............... 27,999
Gain on sale of operations............................. (208)
Deferred income taxes.................................. 6,763
Other non-cash items................................... 633
Change in operating assets and liabilities:
Accounts receivable.................................. 965
Inventories.......................................... (1,516)
Prepaids and other current assets.................... (5,533)
Trade accounts payable............................... (21,088)
Other................................................ (5,348)
--------
Net cash provided by operating activities................... 20,503
--------
Cash flows from investing activities
Property, plant and equipment:
Additions.............................................. (23,713)
Proceeds from sale or restructuring of operations...... 1,166
Property disposals..................................... 214
--------
Net cash used in investing activities....................... (22,333)
--------
Cash flows from financing activities
Investment in subsidiary.................................. (11,142)
Intercompany dividends.................................... (56,138)
--------
Net cash used in financing activities....................... (67,280)
--------
Decrease in net obligations with affiliated Companies....... $(69,110)
========
</TABLE>
The accompanying notes are an integral part of these financial statements.
AF-40
<PAGE> 174
DOMESTIC OPERATIONS OF BLAZER ENERGY CORP. AND SUBSIDIARY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. FINANCIAL STATEMENT PRESENTATION
Blazer Energy Corp. and subsidiary (formerly Ashland Exploration, Inc.)
("Company") operated both domestic and international exploration and production
operations. Immediately prior to the acquisition of the Company by a subsidiary
of Statoil Energy, Inc. (See Note 4), Ashland Inc. (parent company of Blazer
Energy Corp.) removed all international exploration and production operations of
the Company. The accompanying financial statements reflect all domestic
exploration and production operations. The Company is engaged in the exploration
for and the development, production, acquisition and marketing of natural gas
and oil in the United States.
The financial statements include only the domestic accounts of the Company
and its subsidiary. Significant intercompany accounts and transactions have been
eliminated in consolidation. Consistent with industry practice, the Company
utilizes pro rata consolidation to account for its investment in oil and gas
ventures.
The accompanying condensed consolidated financial statements have been
prepared in accordance with generally accepted accounting principles for interim
financial information and with the instructions for Article 10 of Regulation
S-X. The consolidated income statement for the nine months ended June 30, 1997,
and the consolidated statement of cash flows for the nine month period ended
June 30, 1997, are unaudited but include all adjustments (consisting of only
normal recurring adjustments) which the Company considers necessary for a fair
presentation of the operating results and cash flows for this period. Although
the Company believes that the disclosure in the accompanying consolidated
financial statements is adequate to make the information presented not
misleading, certain information normally included in financial statements and
related footnotes prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to the rules and regulations
of the Securities and Exchange Commission. The accompanying financial statements
should be read in conjunction with the consolidated financial statements for the
year ended September 30, 1996 and related footnotes as contained elsewhere
herein.
2. NORM RECLAMATION AND RELATED LIABILITIES
During 1996, the U.S. Environmental Protection Agency and the state of
Kentucky approved the Company's plan of reclamation (including disposal off
site) of naturally occurring radioactive material ("NORM") from the Martha oil
field in Kentucky. The Company's independent contractor began implementing the
NORM reclamation work in September 1996.
3. INCOME TAXES
Income tax benefit has been computed on an interim basis based on the
estimated effective rate for the entire year.
4. SUBSEQUENT EVENT
On July 1, 1997, a subsidiary of Statoil Energy, Inc. ("STEN") entered into
a Stock Purchase Agreement to acquire the domestic operations of Blazer Energy
Corp. for a purchase price of $567.1 million. Items excluded from this
transaction include the Martha Oil Field in Kentucky, including related
environmental obligations, insurance policies, office facilities and leases,
certain fee interests in land and any potential additional recovery related to
the Columbia Gas settlement. Pursuant to this agreement, Ashland agreed to
indemnify STEN from and against losses resulting from certain other
environmental claims and litigation.
AF-41
<PAGE> 175
EXHIBIT A
[RYDER SCOTT LETTERHEAD]
October 1, 1999
Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue, Suite 300
Alexandria, Virginia 22314
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of the Underlying Properties Relating to the Appalachian Natural Gas Trust as of
August 31, 1999. The subject properties are located in the states of Kentucky
and West Virginia. The income data were estimated using the Securities and
Exchange Commission (SEC) guidelines for future price and cost parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. August 1999 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from August 1999 prices. Therefore, volumes
of reserves actually recovered and amounts of income actually received may
differ significantly from the estimated quantities presented in this report. The
results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
APPALACHIAN NATURAL GAS TRUST
(UNDERLYING PROPERTIES)
As of August 31, 1999
<TABLE>
<CAPTION>
PROVED
--------------------------------------------------------------
DEVELOPED
----------------------------
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL PROVED
------------ ------------- -------------- --------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Gas -- MMCF..................... 328,993 588 436,533 766,114
Oil/Condensate -- Barrels....... 259,592 0 0 259,592
INCOME DATA
Future Gross Revenue............ $909,979,004 $1,626,303 $1,218,019,967 $2,129,625,274
Deductions...................... 189,718,479 409,482 468,549,504 658,677,465
------------ ---------- -------------- --------------
Future Net Income (FNI)......... $720,260,525 $1,216,821 $ 749,470,463 $1,470,947,809
Discounted FNI @ 10%............ $264,475,306 $ 385,862 $ 102,416,215 $ 367,277,383
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of 60 degrees Fahrenheit and 14.73 psia.
XA-1
<PAGE> 176
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 2
The future gross revenue is before the deduction of production taxes. In
addition, deductions are comprised of the normal direct costs of operating the
wells, recompletion costs, and development costs. Ad valorem taxes have been
included with production tax calculations. The future net income is before the
deduction of state and federal income taxes and general administrative overhead
and does not include any adjustment for cash on hand or undistributed income. No
attempt was made to quantify or otherwise account for any accumulated gas
production imbalances that may exist. Gas reserves account for approximately
99.8 percent and liquid hydrocarbon reserves account for the remaining 0.2
percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded annually.
RESERVES INCLUDED IN THIS REPORT
The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10(a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definitions
of proved reserves are included under the tab "Reserve Definitions and Pricing
Assumptions" in this report.
The proved developed non-producing reserves included herein are comprised
of behind pipe and shut-in categories. The various reserve status categories are
defined under the tab "Reserve Definitions and Pricing Assumptions" in this
report.
ESTIMATES OF RESERVES
Reserves were estimated by decline curve analysis where sufficient
production history was available. In those cases where sufficient production
history was not available, analogy to offset wells was utilized. Due to the low
permeability of the producing formations, other methods such as material balance
and volumetric methods are inappropriate for determining reserves.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce
was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Eastern States Oil & Gas, Inc. (ESOG).
The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
XA-2
<PAGE> 177
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 3
HYDROCARBON PRICES
ESOG furnished us with prices in effect at August 31, 1999 and these prices
were held constant until depletion of the properties. In accordance with
Securities and Exchange Commission guidelines, changes in liquid and gas prices
subsequent to August 31, 1999 were not taken into account in this report. Future
prices used in this report are discussed in more detail under the tab "Reserve
Definitions and Pricing Assumptions" in this report.
COSTS
Operating costs furnished by ESOG were held constant throughout the life of
the properties, except where changes were known and determinable. These changes
include a two-tier cost structure based upon ESOG's actual operating experience
and practices. ESOG's costs are directly proportional to the level of monitoring
provided by field personnel. Since high rate wells are monitored more closely
than low rate wells, high rate wells have been assigned a higher proportion of
the average operating cost. As a well's production drops below a predetermined
threshold limit (5 MCFD), field personnel reduce the level of monitoring
provided to the well, reducing the well's operating costs, and establishing the
two-tier structure as shown below.
<TABLE>
<CAPTION>
TIER 1 TIER 2
DISTRICT $/WELL/MO $/WELL/MO
-------- --------- ---------
<S> <C> <C>
Brenton...................................... 138 32
Madison...................................... 144 33
Weston....................................... 151 35
Pikeville.................................... 138 32
</TABLE>
An exception to the above are all undeveloped locations which were assigned
$100 per well per month until depletion of the property.
Development costs were furnished to us by ESOG and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. This study does not consider the salvage value of the lease equipment
or the abandonment cost of the subject wells.
GENERAL
While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.
The estimates of reserves presented herein were based upon a detailed study
of the properties in which ESOG owns an interest; however, we have not made any
field examination of the properties. No consideration was given in this report
to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. ESOG has informed us that they have furnished us
all of the accounts, records, geological and engineering data, and reports and
other data required for this investigation. The ownership interests, prices, and
other factual data furnished by ESOG were accepted without independent
verification. The estimates presented in this report are based on data available
through March 1999.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
XA-3
<PAGE> 178
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 4
This report was prepared for the exclusive use and sole benefit of Eastern
States Oil & Gas, Inc. The data, work papers, and maps used in this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
/s/ DON P. GRIFFIN
--------------------
Don P. Griffin, P.E.
Vice President
XA-4
<PAGE> 179
DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated, associated and
dissolved gas. An appropriate reduction in gas reserves has been made for the
expected removal of natural gas liquids, for lease and plant fuel, and for the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.
Proved reserves are estimates of hydrocarbons to be recovered from a given
date forward. They may be revised as hydrocarbons are produced and additional
data become available.
XA-5
<PAGE> 180
RESERVE STATUS CATEGORIES (SEC)
Reserve status categories define the development and producing status of
wells and/or reservoirs.
PROVED DEVELOPED
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Developed reserves may be subcategorized as producing or non-producing
using the SPE/WPC Definitions:
Producing
Reserves sub-categorized as producing are expected to be recovered
from completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after
the improved recovery project is in operation.
Non-Producing
Reserves sub-categorized as non-producing include shut-in and behind
pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which
have not started producing, (2) wells which were shut-in awaiting pipeline
connections or as a result of a market interruption, or (3) wells not
capable of production for mechanical reasons. Behind pipe reserves are
expected to be recovered from zones in existing wells, which will require
additional completion work or future recompletion prior to the start of
production.
PROVED UNDEVELOPED
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Estimates for proved undeveloped reserves are attributable to any
acreage for which an application of fluid injection or other improved technique
is contemplated, only when such techniques have been proved effective by actual
tests in the area and in the same reservoir.
XA-6
<PAGE> 181
HYDROCARBON PRICING PARAMETERS
SECURITIES AND EXCHANGE COMMISSION PARAMETERS
GAS
ESOG furnished us with gas prices in effect at August 31, 1999 as shown
below.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
DISTRICT $/MCF $/MCF
- -------- --------- -----------
<S> <C> <C>
Brenton....................................... 2.756 2.803
Madison....................................... 2.515 2.562
Weston........................................ 2.917 2.964
Pikeville..................................... 2.840 2.887
</TABLE>
Gas prices for undeveloped properties assume that incremental gathering and
compression charges will be lower than developed properties due to synergies in
utilizing existing gathering capacity. This results in an effective higher gas
price.
OIL AND CONDENSATE
ESOG furnished us with oil and condensate prices in effect at August 31,
1999 of $18.75 per barrel, and these prices were held constant to depletion of
the properties. In accordance with Securities and Exchange Commission
guidelines, changes in liquid prices subsequent to August 31, 1999 were not
considered in this report.
XA-7
<PAGE> 182
EXHIBIT B
[RYDER SCOTT LETTERHEAD]
October 1, 1999
Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue, Suite 300
Alexandria, Virginia 22314
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to the Net Profits Interest Relating to the
Appalachian Natural Gas Trust as of August 31, 1999. The subject properties are
located in the states of Kentucky and West Virginia. The income data were
estimated using the Securities and Exchange Commission (SEC) guidelines for
future price and cost parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. August 1999 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from August 1999 prices. Therefore, volumes
of reserves actually recovered and amounts of income actually received may
differ significantly from the estimated quantities presented in this report. The
results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
APPALACHIAN NATURAL GAS TRUST
(NET PROFITS INTEREST)
As of August 31, 1999
<TABLE>
<CAPTION>
PROVED
------------------------------------------------------------
DEVELOPED
----------------------------- TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
------------ ------------- ----------- ------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Gas -- MMCF...................... 209,642 376 29,083 239,101
Oil/Condensate-Barrels........... 170,541 0 0 170,541
INCOME DATA
Future Gross Revenue............. $551,317,578 $987,650 $75,944,127 $628,249,355
Deductions....................... 44,788,484 80,743 6,173,188 51,042,415
------------ -------- ----------- ------------
Future Net Income (FNI).......... $506,529,094 $906,907 $69,770,939 $577,206,940
Discounted FNI @ 10%............. $191,692,164 $279,177 $ 8,448,469 $200,419,810
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of 60 degrees Fahrenheit and 14.73 psia.
XB-1
<PAGE> 183
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 2
The Net Profits Interest (NPI) presented herein is based upon the future
net income (FNI) of the Underlying Properties with adjusted prices and costs.
The results of these adjustments to the Underlying Properties are summarized
below.
APPALACHIAN NATURAL GAS TRUST
(ADJUSTED UNDERLYING PROPERTIES)
As of August 31, 1999
<TABLE>
<CAPTION>
PROVED
--------------------------------------------------------------
DEVELOPED
---------------------------- TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
------------ ------------- -------------- --------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Gas -- MMCF........................ 327,741 588 436,533 764,862
Oil/Condensate -- Barrels.......... 259,486 0 0 259,486
INCOME DATA
Future Gross Revenue............... $861,796,470 $1,545,534 $1,137,697,964 $2,001,039,968
Deductions......................... 228,634,858 411,901 439,988,603 669,035,362
------------ ---------- -------------- --------------
Future Net Income (FNI)............ $633,161,612 $1,133,633 $ 697,709,361 $1,332,004,606
Discounted FNI @ 10%............... $239,615,162 $ 348,972 $ 84,484,734 $ 324,448,868
</TABLE>
The NPI for developed and undeveloped properties has been taken as 80
percent and 10 percent of the FNI of the developed and undeveloped properties as
found in the Adjusted Underlying Properties, respectively. Utilizing these
fractional FNIs, equivalent net reserves and production were back-calculated
assuming a royalty ownership. Therefore, no deductions other than production
taxes are shown in the NPI presentation.
The deductions for Adjusted Underlying Properties are comprised of
production taxes and the normal direct costs of operating the wells,
recompletion costs, and development costs. Ad valorem taxes have been included
with production tax calculations. The future net income is before the deduction
of state and federal income taxes and general administrative overhead and does
not include any adjustment for cash on hand or undistributed income. No attempt
was made to quantify or otherwise account for any accumulated gas production
imbalances that may exist.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded annually.
RESERVES INCLUDED IN THIS REPORT
The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10(a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definitions
of proved reserves are included under the tab "Reserve Definitions and Pricing
Assumptions" in this report.
The proved developed non-producing reserves included herein are comprised
of behind pipe and shut-in categories. The various reserve status categories are
defined under the tab "Reserve Definitions and Pricing Assumptions" in this
report.
ESTIMATES OF RESERVES
Reserves were estimated by decline curve analysis where sufficient
production history was available. In those cases where sufficient production
history was not available, analogy to offset wells was utilized. Due
XB-2
<PAGE> 184
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 3
to the low permeability of the producing formations, other methods such as
material balance and volumetric methods are inappropriate for determining
reserves.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce
was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Eastern States Oil & Gas, Inc. (ESOG).
The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
HYDROCARBON PRICES
ESOG furnished us with prices in effect at August 31, 1999 and these prices
were held constant until depletion of the properties. In accordance with
Securities and Exchange Commission guidelines, changes in liquid and gas prices
subsequent to August 31, 1999 were not taken into account in this report. Future
prices used in this report are discussed in more detail under the tab "Reserve
Definitions and Pricing Assumptions" in this report.
COSTS
Operating costs furnished by ESOG were held constant throughout the life of
the properties, except where changes were known and determinable. These changes
include a two-tier cost structure based upon ESOG's actual operating experience
and practices. ESOG's costs are directly proportional to the level of monitoring
provided by field personnel. Since high rate wells are monitored more closely
than low rate wells, high rate wells have been assigned a higher proportion of
the average operating cost. As a well's production drops below a predetermined
threshold limit (5 MCFD), field personnel reduce the level of monitoring
provided to the well, reducing the well's operating costs, and establishing the
two-tier structure as shown below.
<TABLE>
<CAPTION>
TIER 1 TIER 2
DISTRICT $/WELL/MO $/WELL/MO
- -------- --------- ---------
<S> <C> <C>
Brenton...................................... 170 70
Madison...................................... 170 70
Weston....................................... 170 70
Pikeville.................................... 170 70
</TABLE>
XB-3
<PAGE> 185
Eastern States Oil & Gas, Inc.
October 1, 1999
Page 4
Development costs were furnished to us by ESOG and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. This study does not consider the salvage value of the lease equipment
or the abandonment cost of the subject wells.
GENERAL
While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.
The estimates of reserves presented herein were based upon a detailed study
of the properties in which ESOG owns an interest; however, we have not made any
field examination of the properties. No consideration was given in this report
to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. ESOG has informed us that they have furnished us
all of the accounts, records, geological and engineering data, and reports and
other data required for this investigation. The ownership interests, prices, and
other factual data furnished by ESOG were accepted without independent
verification. The estimates presented in this report are based on data available
through March 1999.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
This report was prepared for the exclusive use and sole benefit of Eastern
States Oil & Gas, Inc. The data, work papers, and maps used in this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
/s/ DON P. GRIFFIN
--------------------
Don P. Griffin, P.E.
Vice President
XB-4
<PAGE> 186
DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated, associated and
dissolved gas. An appropriate reduction in gas reserves has been made for the
expected removal of natural gas liquids, for lease and plant fuel, and for the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.
Proved reserves are estimates of hydrocarbons to be recovered from a given
date forward. They may be revised as hydrocarbons are produced and additional
data become available.
XB-5
<PAGE> 187
RESERVE STATUS CATEGORIES (SEC)
Reserve status categories define the development and producing status of
wells and/or reservoirs.
PROVED DEVELOPED
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Developed reserves may be subcategorized as producing or non-producing
using the SPE/WPC Definitions:
Producing
Reserves sub-categorized as producing are expected to be recovered
from completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after
the improved recovery project is in operation.
Non-Producing
Reserves sub-categorized as non-producing include shut-in and behind
pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which
have not started producing, (2) wells which were shut-in awaiting pipeline
connections or as a result of a market interruption, or (3) wells not
capable of production for mechanical reasons. Behind pipe reserves are
expected to be recovered from zones in existing wells, which will require
additional completion work or future recompletion prior to the start of
production.
PROVED UNDEVELOPED
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Estimates for proved undeveloped reserves are attributable to any
acreage for which an application of fluid injection or other improved technique
is contemplated, only when such techniques have been proved effective by actual
tests in the area and in the same reservoir.
XB-6
<PAGE> 188
HYDROCARBON PRICING PARAMETERS
SECURITIES AND EXCHANGE COMMISSION PARAMETERS
GAS
ESOG furnished us with gas prices in effect at August 31, 1999 as shown
below.
<TABLE>
<CAPTION>
DISTRICT $/MCF
-------- -----
<S> <C>
Brenton..................................................... 2.619
Madison..................................................... 2.378
Weston...................................................... 2.780
Pikeville................................................... 2.703
</TABLE>
OIL AND CONDENSATE
ESOG furnished us with oil and condensate prices in effect at August 31,
1999 of $18.75 per barrel, and these prices were held constant to depletion of
the properties. In accordance with Securities and Exchange Commission
guidelines, changes in liquid prices subsequent to August 31, 1999 were not
considered in this report.
XB-7
<PAGE> 189
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
APPALACHIAN NATURAL GAS TRUST
7,875,000 TRUST UNITS
---------------------
PROSPECTUS
, 1999
---------------------
LEHMAN BROTHERS
SALOMON SMITH BARNEY
PAINEWEBBER INCORPORATED
CIBC WORLD MARKETS
CREDIT SUISSE FIRST BOSTON
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
DONALDSON, LUFKIN & JENRETTE
A.G. EDWARDS & SONS, INC.
MCDONALD INVESTMENTS INC.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 190
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
All capitalized terms used and not defined in Part II of this Registration
Statement shall have the meanings assigned to them in the Prospectus forming a
part of this Registration Statement.
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
Except for the Registration Fee and the NASD Filing Fee, the following
itemized table sets forth estimates of those expenses payable by Eastern States
in connection with the offer and sale of the securities offered hereby:
<TABLE>
<S> <C>
Registration Fee............................................ $ 52,871
NASD Filing Fee............................................. 19,519
NYSE Listing Fee............................................ 103,850
Printing and Engraving Expenses............................. *
Legal Fees and Expenses..................................... *
Accountants' Fees and Expenses.............................. *
Trustee's Fees and Expenses................................. *
Blue Sky Fees............................................... *
Miscellaneous Fees and Expenses............................. *
--------
Total.............................................
========
</TABLE>
- ---------------
* To be filed by amendment
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Section 7 of the Trust Agreement provides that the trustee will be
indemnified by Eastern States Oil & Gas, Inc., a Delaware corporation, against
any and all liability and expenses incurred by it individually or as trustee in
the administration of the trust and the trust estate, except for any liability
or expense resulting from willful misconduct, bad faith or gross negligence.
Subsection (a) of Section 145 of the General Corporation Law of the State
of Delaware ("DGCL") empowers a corporation to indemnify any person who was or
is a party or is threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal, administrative or
investigative (other than an action by or in the right of the corporation) by
reason of the fact that he is or was a director, officer, employee or agent of
the corporation, or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation, partnership, joint
venture, trust or other enterprise, against expenses (including attorneys'
fees), judgments, fines and amounts paid in settlement actually and reasonably
incurred by him in connection with such action, suit or proceeding if he acted
in good faith and in a manner he reasonably believed to be in or not opposed to
the best interests of the corporation, and, with respect to any criminal action
or proceeding, had no reasonable cause to believe his conduct was unlawful.
Subsection (b) of Section 145 empowers a corporation to indemnify any
person who was or is a party or is threatened to be made a party to any
threatened, pending or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the fact that such
person acted in any of the capacities set forth above, against expenses
(including attorneys' fees) actually and reasonably incurred by him in
connection with the defense or settlement of such action or suit if he acted in
good faith and in a manner he reasonably believed to be in or not opposed to the
best interests of the corporation, except that no indemnification may be made in
respect of any claim, issue or matter as to which such person shall have been
adjudged to be liable to the corporation unless and only to the extent that the
Court of Chancery or the court in which such action or suit was brought shall
determine upon application that, despite the adjudication of liability but in
view of all the circumstances of the case, such person is fairly and reasonably
entitled to indemnity for such expenses which the Court of Chancery or such
other court shall deem proper.
II-1
<PAGE> 191
Section 145 further provides that to the extent a director or officer of a
corporation has been successful on the merits or otherwise in the defense of any
action, suit or proceeding referred to in subsections (a) and (b) of Section 145
or in the defense of any claim, issue or matter therein, he shall be indemnified
against expenses (including attorneys' fees) actually and reasonably incurred by
him in connection therewith; that indemnification provided for by Section 145
shall not be deemed exclusive of any other rights to which the indemnified party
may be entitled; that indemnification provided by Section 145 shall, unless
otherwise provided when authorized or ratified, continue as to a person who has
ceased to be a director, officer, employee or agent and shall inure to the
benefit of such person's heirs, executors and administrators; and empowers the
corporation to purchase and maintain insurance on behalf of a director or
officer of the corporation against any liability asserted against him and
incurred by him in any such capacity, or arising out of his status as such,
whether or not the corporation would have the power to indemnify him against
such liabilities under Section 145.
Section 102(b)(7) of the DGCL provides that a certificate of incorporation
may contain a provision eliminating or limiting the personal liability of a
director to the corporation or its stockholders for monetary damages for breach
of fiduciary duty as a director, provided that such provisions may not eliminate
or limit the liability of a director (1) for any breach of the director's duty
of loyalty to the corporation or its stockholders, (2) for acts or omissions not
in good faith or which involve intentional misconduct or a knowing violation of
law, (3) under Section 174 (relating to liability for unauthorized acquisitions
or redemptions of, or dividends on, capital stock) of the DGCL or (4) for any
transaction from which the director derived an improper personal benefit.
Article VII of Eastern States' Amended and Restated Certificate of Incorporation
contains such a provision.
Section 8.07 of Eastern States' Amended and Restated Bylaws further
provides that:
"(a) The Corporation shall indemnify a director or officer of the
Corporation who is or was a party to any proceeding by reason of the fact
that he is or was such a director or officer or is or was serving at the
request of the Corporation as a director, officer, employee or agent of
another corporation, partnership, joint venture, trust, employee benefit
plan or other profit or non-profit enterprise against all liabilities and
expenses incurred in the proceeding to the maximum extent permissible under
applicable law.
(b) To the maximum extent permissible under applicable law, the
Corporation shall make advances and reimbursements for expenses incurred by
a director or officer in a proceeding upon receipt of an undertaking from
him to repay the same if it is ultimately determined that he is not
entitled to indemnification. Such undertaking shall be an unlimited,
unsecured general obligation of the director or officer and shall be
accepted without reference to his ability to make repayment. The Executive
Committee is hereby designated as an appropriate committee to authorize
such advances/reimbursements.
(c) The Board of Directors is hereby empowered, by majority vote of a
quorum of disinterested directors, to cause the Corporation to indemnify or
contract in advance to indemnify any other employee or agent of the
Corporation not specified in subsection (a) of this Section 8.07 who was or
is a party to any proceeding, by reason of the fact that he is or was an
employee or agent of the Corporation, or is or was serving at the request
of the Corporation as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust, employee benefit plan or
other profit or non-profit enterprise, to the same extent as if such person
was specified as one to whom indemnification is granted in subsection (a).
(d) The Corporation may purchase and maintain insurance to indemnify
it against the whole or any portion of the liability assumed by it in
accordance with this Section 8.07 and may also procure insurance, in such
amounts as the Board of Directors may determine, on behalf of any person
who is or was a director, officer, employee or agent of another
corporation, partnership, joint venture, trust, employee benefit plan or
other enterprise, against any liability asserted against or incurred by
such person in any such capacity or arising from his status as such,
whether or not the Corporation would have power to indemnify him against
such liability under the provisions of this Section 8.07.
II-2
<PAGE> 192
(e) In the event there has been a change in the composition of a
majority of the Board of Directors after the date of an alleged act or
omission with respect to which indemnification is claimed, any
determination as to indemnification and advancement of expenses with
respect to any claim for indemnification made pursuant to subsection (a) of
this Section 8.07 shall be made by special legal counsel agreed upon by the
Board of Directors and the proposed indemnitee. If the Board of Directors
and the proposed indemnitee are unable to agree upon such special legal
counsel, the Board of Directors and the proposed indemnitee each shall
select a nominee, and the nominees shall select such special legal counsel.
(f) The provisions of this Section 8.07 shall be applicable to all
actions, claims, suits or proceedings commenced after the adoption hereof,
whether arising from any action taken or failure to act before or after
such adoption. No amendment, modification or repeal of this Section 8.07
shall diminish the rights provided hereby or diminish the right to
indemnification with respect to any claim, issue or matter in any then
pending or subsequent proceeding that is based in any material respect on
any alleged action or failure to act prior to such amendment, modification
or repeal.
(g) Reference herein to directors, officers, employees or agents shall
include former directors, officers, employees and agents and their
respective heirs, executors and administrators.
(h) If any provision or provisions of this Section 8.07 shall be held
to be invalid, illegal or unenforceable for any reason whatsoever: (i) the
validity, legality and enforceability of the remaining provisions of this
Section 8.07 (including, without limitation, all portions of Section 8.07
containing any such provision held to be invalid, illegal or unenforceable,
that are not themselves invalid, illegal or unenforceable) shall not in any
way be affected or impaired thereby; and (ii) to the fullest extent
possible, the provisions of this Section 8.07 (including, without
limitation, all portions of Section 8.07 containing any such provision held
to be invalid, illegal or unenforceable, that are not themselves invalid,
illegal or unenforceable) shall be construed so as to give effect to the
intent manifested by the provision held invalid, illegal or unenforceable."
In addition, Eastern States and certain other persons may be entitled under
agreements entered into with agents or underwriters to indemnification by such
agents or underwriters against certain liabilities, including liabilities under
the Securities Act of 1933, or to contribution with respect to payments which
Eastern States or such persons may be required to make in respect thereof.
The above discussion of Eastern States' Amended and Restated Certificate of
Incorporation, Amended and Restated Bylaws and Sections 145 and 102(b)(7) of the
DGCL is not intended to be exhaustive and is qualified in its entirety by such
Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws
and statutes.
Additionally, Eastern States has acquired directors' and officers'
insurance in the amount of $10 million.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
None
ITEM 16. EXHIBITS.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
** 1.1 -- Form of Underwriting Agreement.
* 3.1 -- Amended and Restated Certificate of Incorporation of
Eastern States Oil & Gas, Inc.
* 3.2 -- Amended and Restated Bylaws of Eastern States Oil & Gas,
Inc.
* 4.1.1 -- Certificate of Trust.
** 4.1.2 -- Certificate of Amendment to Certificate of Trust filed
October 8, 1999.
** 4.2 -- Appalachian Natural Gas Trust -- Restated Trust
Agreement, dated as of October 4, 1999.
</TABLE>
II-3
<PAGE> 193
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
** 4.3 -- Appalachian Natural Gas Trust -- Form of Amended and
Restated Trust Agreement.
** 5.1 -- Opinion of Richards, Layton & Fingers, P.A. as to the
legality of the securities offered hereby.
** 8.1 -- Form of Opinion of Andrews & Kurth L.L.P. regarding
federal income tax matters.
** 8.2 -- Form of Opinion of Goodwin & Goodwin regarding West
Virginia state tax matters.
** 8.3 -- Form of Opinion of Vorys, Sater, Seymour and Pease, LLP
regarding Kentucky state tax matters.
**10.1 -- Form of Net Overriding Royalty Conveyance.
*10.2 -- Amended and Restated Incentive Compensation Plan of
Statoil Energy, Inc.
*10.3.1 -- Employee Shareholders Agreement dated May 31, 1995 by and
among Statoil Energy, Inc. and the signatories thereto
who hold Statoil Energy, Inc. common stock and/or options
to purchase common stock.
*10.3.2 -- First Amendment to Employee Shareholders Agreement dated
June 6, 1997 by and among Statoil Energy and the
signatories thereto who hold Statoil Energy common stock
and/or options to purchase common stock.
*10.3.3 -- Second Amendment to Employee Shareholders Agreement dated
May 19, 1998 by and among Statoil Energy and the
signatories thereto who hold Statoil common stock and/or
options to purchase common stock.
*10.4 -- Promissory Note dated August 10, 1999 made by Eastern
States Oil & Gas, Inc. to Statoil Energy Holdings, Inc.
for the principal sum of $505,488,085.
*10.5.1 -- Employment Agreement between Clifton A. Brown and Statoil
Energy effective February 1, 1999.
*10.5.2 -- Employment Agreement between Stevens V. Gillespie and
Statoil Energy effective February 1, 1999.
**10.6 -- Gas Purchase Contract between Eastern States Oil & Gas,
Inc. and CNG Energy Services Corporation dated November
1, 1997.
**10.7 -- Gas Purchase Contract between Statoil Energy, Inc. and
CNG Producing Company dated August 1, 1998.
**10.8 -- Natural Gas Sales Agreement between Eastern Energy
Marketing, Inc. and Eastern States Oil & Gas, Inc. dated
October 23, 1996.
*21.1 -- Subsidiaries of Eastern States Oil & Gas, Inc.
**23.1 -- Consent of Ernst & Young LLP dated October 13, 1999.
**23.2 -- Consent of Richards, Layton & Fingers, P.A. (included in
the opinion filed as Exhibit 5.1).
**23.3 -- Form of Consent of Andrews & Kurth L.L.P. (included in
the opinion filed as Exhibit 8.1).
**23.4 -- Consent of Ryder Scott Company, L.P. Petroleum Engineers
dated October 13, 1999.
**23.5 -- Form of Consent of Goodwin & Goodwin (included in the
opinion filed as Exhibit 8.2).
**23.6 -- Form of Consent of Vorys, Sater, Seymour and Pease LLP
(included in the opinion filed as Exhibit 8.3).
*24.1 -- Power of attorney.
*27.1 -- Financial Data Schedule relating to Appalachian Natural
Gas Trust.
*27.2 -- Financial Data Schedule relating to Eastern States Oil &
Gas, Inc.
</TABLE>
- ---------------
* Previously filed.
** Filed herewith.
II-4
<PAGE> 194
ITEM 17. UNDERTAKINGS.
The registrants hereby undertake:
(a) To provide to the underwriters at the closing specified in the
underwriting agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt delivery to
each purchaser.
(b) That, for purposes of determining any liability under the
Securities Act of 1933, the information omitted from the form of prospectus
filed as part of this Registration Statement in reliance upon Rule 430A and
contained in a form of prospectus filed by the registrants pursuant to Rule
424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed a part
of this Registration Statement as of the time it was declared effective.
(c) That, for the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that contains a form
of prospectus shall be deemed to be a new registration statement relating
to the securities offered therein, and the offering of such securities at
that time shall be deemed to be the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of each
of the registrants pursuant to the provisions described in Item 14 above or
otherwise, each registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy
as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In
the event that claim for indemnification against such liabilities (other than
the payment by Eastern States of expenses incurred or paid by a director,
officer or controlling person of each of the registrants in the successful
defense of any action, suit or proceeding) is asserted by such director, officer
or controlling person in connection with the securities being registered, each
registrant will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of appropriate jurisdiction
the question whether such indemnification by it is against public policy as
expressed in the Securities Act of 1933 and will be governed by the final
adjudication of such issue.
II-5
<PAGE> 195
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Amendment No. 1 to the Registration Statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Alexandria, State of Virginia, on October 14, 1999.
EASTERN STATES OIL & GAS, INC.
By: /s/ CLIFTON A. BROWN
----------------------------------
Name: Clifton A. Brown
Title: President and Chief
Executive Officer
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Amendment No. 1 to the Registration Statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Alexandria, State of Virginia, on October 14, 1999.
APPALACHIAN NATURAL GAS TRUST
By: EASTERN STATES OIL & GAS, INC.,
as sponsor
By: /s/ CLIFTON A. BROWN
----------------------------------
Name: Clifton A. Brown
Title: President and Chief
Executive Officer
Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 1 to the Registration Statement has been signed by the following persons in
the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ CLIFTON A. BROWN President and Chief Executive October 14, 1999
- ----------------------------------------------------- Officer (Principal Executive
Clifton A. Brown Officer)
/s/ STEVENS V. GILLESPIE Senior Vice President, Chief October 14, 1999
- ----------------------------------------------------- Financial Officer and
Stevens V. Gillespie Treasurer (Principal
Financial Officer and
Principal Accounting
Officer)
* Director October 14, 1999
- -----------------------------------------------------
David A. Dresner
* Director October 14, 1999
- -----------------------------------------------------
Kristian B. Hausken
</TABLE>
II-6
<PAGE> 196
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
* Director October 14, 1999
- -----------------------------------------------------
Jon A. Jacobsen
* Director October 14, 1999
- -----------------------------------------------------
Thor Otto Lohne
* Director October 14, 1999
- -----------------------------------------------------
Johan Nic Vold
*By /s/ CLIFTON A. BROWN
-------------------------------------------------
Clifton A. Brown
Attorney-in-Fact
</TABLE>
II-7
<PAGE> 197
EXHIBIT INDEX
ITEM 16. EXHIBITS.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
** 1.1 -- Form of Underwriting Agreement.
* 3.1 -- Amended and Restated Certificate of Incorporation of
Eastern States Oil & Gas, Inc.
* 3.2 -- Amended and Restated Bylaws of Eastern States Oil & Gas,
Inc.
* 4.1.1 -- Certificate of Trust.
** 4.1.2 -- Certificate of Amendment to Certificate of Trust filed
October 8, 1999.
** 4.2 -- Appalachian Natural Gas Trust -- Restated Trust
Agreement, dated as of October 4, 1999.
** 4.3 -- Appalachian Natural Gas Trust -- Form of Amended and
Restated Trust Agreement.
** 5.1 -- Opinion of Richards, Layton & Fingers, P.A. as to the
legality of the securities offered hereby.
** 8.1 -- Form of Opinion of Andrews & Kurth L.L.P. regarding
federal income tax matters.
** 8.2 -- Form of Opinion of Goodwin & Goodwin regarding West
Virginia state tax matters.
** 8.3 -- Form of Opinion of Vorys, Sater, Seymour and Pease, LLP
regarding Kentucky state tax matters.
**10.1 -- Form of Net Overriding Royalty Conveyance.
*10.2 -- Amended and Restated Incentive Compensation Plan of
Statoil Energy, Inc.
*10.3.1 -- Employee Shareholders Agreement dated May 31, 1995 by and
among Statoil Energy, Inc. and the signatories thereto
who hold Statoil Energy, Inc. common stock and/or options
to purchase common stock.
*10.3.2 -- First Amendment to Employee Shareholders Agreement dated
June 6, 1997 by and among Statoil Energy and the
signatories thereto who hold Statoil Energy common stock
and/or options to purchase common stock.
*10.3.3 -- Second Amendment to Employee Shareholders Agreement dated
May 19, 1998 by and among Statoil Energy and the
signatories thereto who hold Statoil common stock and/or
options to purchase common stock.
*10.4 -- Promissory Note dated August 10, 1999 made by Eastern
States Oil & Gas, Inc. to Statoil Energy Holdings, Inc.
for the principal sum of $505,488,085.
*10.5.1 -- Employment Agreement between Clifton A. Brown and Statoil
Energy effective February 1, 1999.
*10.5.2 -- Employment Agreement between Stevens V. Gillespie and
Statoil Energy effective February 1, 1999.
**10.6 -- Gas Purchase Contract between Eastern States Oil & Gas,
Inc. and CNG Energy Services Corporation dated November
1, 1997.
**10.7 -- Gas Purchase Contract between Statoil Energy, Inc. and
CNG Producing Company dated August 1, 1998.
**10.8 -- Natural Gas Sales Agreement between Eastern Energy
Marketing, Inc. and Eastern States Oil & Gas, Inc. dated
October 23, 1996.
*21.1 -- Subsidiaries of Eastern States Oil & Gas, Inc.
**23.1 -- Consent of Ernst & Young LLP dated October 13, 1999.
**23.2 -- Consent of Richards, Layton & Fingers, P.A. (included in
the opinion filed as Exhibit 5.1).
</TABLE>
II-8
<PAGE> 198
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
**23.3 -- Form of Consent of Andrews & Kurth L.L.P. (included in
the opinion filed as Exhibit 8.1).
**23.4 -- Consent of Ryder Scott Company, L.P. Petroleum Engineers
dated October 13, 1999.
**23.5 -- Form of Consent of Goodwin & Goodwin (included in the
opinion filed as Exhibit 8.2).
**23.6 -- Form of Consent of Vorys, Sater, Seymour and Pease LLP
(included in the opinion filed as Exhibit 8.3).
*24.1 -- Power of attorney.
*27.1 -- Financial Data Schedule relating to Appalachian Natural
Gas Trust.
*27.2 -- Financial Data Schedule relating to Eastern States Oil &
Gas, Inc.
</TABLE>
- ---------------
* Previously filed.
** Filed herewith.
II-9
<PAGE> 1
EXHIBIT 1.1
Draft
APPALACHIAN NATURAL GAS TRUST
7,875,000 TRUST UNITS
------------------
UNDERWRITING AGREEMENT
, 1999
------
LEHMAN BROTHERS INC.
SALOMON SMITH BARNEY INC.
PAINEWEBBER INCORPORATED
CIBC WORLD MARKETS CORP.
CREDIT SUISSE FIRST BOSTON CORPORATION
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
DONALDSON, LUFKIN & JENRETTE SECURITIES CORPORATION
A.G. EDWARDS & SONS, INC.
MCDONALD INVESTMENTS INC.
As Representatives of the several
Underwriters named in Schedule 1 hereto,
c/o LEHMAN BROTHERS INC.
Three World Financial Center
New York, New York 10285
Dear Sirs:
Eastern States Oil & Gas, Inc., a Delaware corporation (the "Company"),
proposes to sell to the Underwriters named in Schedule 1 hereto (the
"Underwriters") 7,875,000 units (the "Firm Units") of beneficial interest (the
"Trust Units") in the Appalachian Natural Gas Trust, a grantor trust formed
under the laws of the State of Delaware (the "Trust") to hold net profits
interests (the "Net Profits Interests") in certain natural gas producing
properties owned by the Company (the "Underlying Properties") in the Appalachian
Basin area of Kentucky and West Virginia. In addition, the Company proposes to
grant to the Underwriters an option to purchase up to an additional 1,181,250
Trust Units on the terms and for the purposes set forth in Section 2 (the
"Option Units"). The Firm Units and the Option Units, if purchased, are
hereinafter collectively called the "Units."
1. Representations and Warranties of the Statoil Parties. The Company,
Statoil Energy, Inc., a Virginia corporation ("Statoil Energy"), and Statoil
Energy Holdings, Inc., a Delaware corporation ("Statoil Energy Holdings" and,
collectively with the Company and Statoil Energy, the
<PAGE> 2
"Statoil Parties"), jointly and severally represent and warrant to, and agree
with, each of the Underwriters that:
(a) A joint registration statement on Form S-1 (File No. 333-85955)
with respect to the Units (i) has been prepared by the Company and the Trust in
conformity with the requirements of the Securities Act of 1933, as amended (the
"Securities Act"), and the rules and regulations (the "Rules and Regulations")
of the Securities and Exchange Commission (the "Commission") thereunder, (ii)
has been filed with the Commission under the Securities Act and (iii) has become
effective under the Securities Act. Copies of such registration statement as
amended to date have been delivered by the Company to you as the representatives
(the "Representatives") of the Underwriters. As used in this Agreement,
"Effective Time" means the date and the time as of which such registration
statement, or the most recent post-effective amendment thereto, if any, was
declared effective by the Commission; "Effective Date" means the date of the
Effective Time; "Preliminary Prospectus" means each prospectus included in such
registration statement, or amendments thereof, before it became effective under
the Securities Act and any prospectus filed with the Commission by the Company
and the Trust with the consent of the Representatives pursuant to Rule 424(a) of
the Rules and Regulations; "Registration Statement" means such registration
statement, as amended at the Effective Time, including, if the Effective Date is
on or before the date of this Agreement, all information contained in the final
prospectus filed with the Commission pursuant to Rule 424(b) of the Rules and
Regulations ("Rule 424(b)") in accordance with Section 5(a) hereof and deemed to
be a part of the registration statement as of the Effective Time pursuant to
paragraph (b) of Rule 430A of the Rules and Regulations; and "Prospectus" means
such final prospectus, as first filed with the Commission pursuant to paragraph
(1) or (4) of Rule 424(b) of the Rules and Regulations. If it is contemplated,
at the time this Agreement is executed, that a registration statement or
post-effective amendment will be filed pursuant to Rule 462(b) or Rule 462(d)
under the Securities Act before the offering of the Units may commence, the term
"Registration Statement" as used in this Agreement includes such registration
statement. The Commission has not issued any order preventing or suspending the
use of any Preliminary Prospectus.
(b) Any Preliminary Prospectus, at the date of filing thereof with the
Commission, conformed in all material respects with the requirements of the
Securities Act and the Rules and Regulations and did not contain an untrue
statement of a material fact or omit to state a material fact required to be
stated therein or necessary in order to make the statements therein, in the
light of the circumstances under which they were made, not misleading. The
Registration Statement conforms, and the Prospectus and any further amendments
or supplements to the Registration Statement or the Prospectus will, when they
become effective or are filed with the Commission, conform in all material
respects to the requirements of the Securities Act and the Rules and Regulations
and do not and will not, as of the applicable effective date (as to the
Registration Statement and any amendment thereto) and as of the applicable
filing date (as to the Prospectus and any amendment or supplement thereto)
contain an untrue statement of a material fact or omit to state a material fact
required to be stated therein or necessary to make the statements therein not
misleading. Each of the statements made by the Company and the Trust in such
documents within the coverage of Rule 175(b) of the Rules and Regulations,
including (but not limited to) any statements with respect to future cash
distributions of the Trust, was made or will be made with a reasonable basis and
in good faith.
-2-
<PAGE> 3
Notwithstanding the foregoing, no representation and warranty is made as to
information contained in or omitted from the Registration Statement, the
Prospectus or any Preliminary Prospectus in reliance upon and in conformity with
written information furnished to the Company or the Trust by or on behalf of any
Underwriter through the Representatives specifically for inclusion therein.
(c) Each of the Company and Statoil Energy Holdings has been duly
incorporated and is validly existing as a corporation in good standing under the
laws of the State of Delaware, with full corporate power and authority to own or
lease its properties and conduct its business, in each case in all material
respects as described in the Registration Statement and the Prospectus. Each of
the Company and Statoil Energy Holdings has been duly registered or qualified as
a foreign corporation for the transaction of business and is in good standing
under the laws of each jurisdiction (in the case of the Company, including but
not limited to, Kentucky and West Virginia) in which the character of the
business conducted by it or the nature or location of the properties owned or
leased by it makes such registration or qualification necessary, except where
the failure to so register or qualify would not have a material adverse effect
on the condition (financial or other), business, prospects, properties, net
worth or results of operations of the Statoil Parties or the Trust.
(d) Statoil Energy has been duly incorporated and is validly existing
as a corporation in good standing under the laws of the Commonwealth of
Virginia, with full corporate power and authority to own or lease its properties
and conduct its business, in each case in all material respects as described in
the Registration Statement and the Prospectus. Statoil Energy has been duly
registered or qualified as a foreign corporation for the transaction of business
and is in good standing under the laws of each jurisdiction (in the case of the
Company, including but not limited to, Kentucky and West Virginia) in which the
character of the business conducted by it or the nature or location of the
properties owned or leased by it makes such registration or qualification
necessary, except where the failure to so register or qualify would not have a
material adverse effect on the condition (financial or otherwise), business,
prospects, properties, net worth or results of operations of the Statoil Parties
or the Trust.
(e) None of the subsidiaries of the Company is a "significant
subsidiary" (as such term is defined in Rule 405 of the Rules and Regulations).
(f) Statoil Energy owns 100% of the outstanding common stock of Statoil
Energy Holdings; such common stock has been duly authorized and validly issued
and is fully paid and nonassessable; and Statoil Energy owns such common stock
free and clear of all liens, encumbrances, security interests, equities, charges
or claims.
(g) Statoil Energy Holdings owns 100% of the outstanding common stock
of the Company; such common stock has been duly authorized and validly issued
and is fully paid and nonassessable; and Statoil Energy Holdings owns such
common stock free and clear of all liens, encumbrances, security interests,
equities, charges or claims.
-3-
<PAGE> 4
(h) The Trust has been duly formed and is validly existing as a
business trust under the laws of the State of Delaware and has full trust power
and authority to own or lease its properties as described in the Prospectus.
(i) This Agreement has been duly authorized, executed and delivered by
the Statoil Parties; at or before the First Delivery Date (as defined in Section
4), an amended and restated trust agreement (the "Trust Agreement") will have
been duly authorized, executed and delivered by the Company, as grantor, Bank
One Texas, N.A., a banking association organized under the laws of the United
States (the "Trustee"), as trustee, and Bank One Delaware, Inc., a banking
association organized under the laws of the United States (the "Delaware
Trustee"), as Delaware trustee, and will be a valid and legally binding
obligation of the Company enforceable against the Company in accordance with its
terms; at or before the First Delivery Date, each of the Net Overriding Royalty
Conveyance (Kentucky), as amended and restated, effective September 1, 1999,
executed by the Company in favor of the Trustee, and the Net Overriding Royalty
Conveyance (West Virginia), as amended and restated, effective September 1,
1999, executed by the Company in favor of the Trustee (collectively, the
"Conveyances"), will have been duly authorized, executed and delivered by the
Company and will be a valid and legally binding obligation of the Company
enforceable against the Company in accordance with its terms; provided that the
enforceability of the Trust Agreement and the Conveyances may be limited by
bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and
similar laws relating to or affecting creditors' rights generally and by general
principles of equity (regardless of whether such enforceability is considered in
a proceeding in equity or at law); and provided further that the indemnity,
contribution and exoneration provisions contained in any of such agreements may
be limited by applicable laws and public policy. The Trust Agreement, the Trust
Units and the Conveyances will conform in all material respects to the
descriptions thereof in the Prospectus.
(j) Each of the Trustee and the Delaware Trustee is a national banking
association duly authorized and empowered to act as trustee of the Trust
pursuant to the Trust Agreement.
(k) Prior to the First Delivery Date, the Company will have made all
necessary filings in the jurisdictions referred to in the Conveyances and, with
respect to Net Profits Interests burdening federal or Indian lands, all
necessary filings required under federal law, including without limitation the
filing of the Conveyances for recordation in the appropriate records pursuant to
local recordation laws and, with respect to Net Profits Interests burdening
federal and Indian lands, pursuant to applicable federal law.
(l) At or prior to the First Delivery Date, the Company will have
assigned and contributed to the Trust the Net Profits Interests as described in
the Prospectus.
(m) At the First Delivery Date, except for liens and encumbrances
described in clauses (i), (ii), (iii), (iv) and (v) of Section 1(z) hereof, (i)
any and all liens or encumbrances on the Underlying Properties will be
subordinated to the Net Profits Interests, and (ii) all future liens or
encumbrances on the Underlying Properties shall be subordinate and inferior to
the Net Profits Interests.
-4-
<PAGE> 5
(n) Immediately prior to the First Delivery Date, the Company will own
10,500,000 Trust Units; all of such Trust Units will have been duly authorized
in accordance with the Trust Agreement and, when duly executed and countersigned
in accordance with the provisions of the Trust Agreement and delivered to the
Company in exchange for the Net Profits Interests pursuant to the Conveyances,
will be validly issued, fully paid and nonassessable and entitled to the
benefits of the Trust Agreement; and the Company will own such Trust Units free
and clear of all liens, encumbrances, security interests, equities, charges or
claims.
(o) The Company has, and immediately prior to each Delivery Date (as
defined in Section 4) the Company will have, good and valid title to the Units
to be sold by the Company hereunder, free and clear of all liens, encumbrances,
security interests, equities, charges or claims, and the Company has full
corporate power and authority to sell, assign, transfer and deliver such Trust
Units hereunder; and, upon the delivery to the Underwriters of certificates
evidencing the Units issued in the name of the Underwriters or their designees
and payment therefor pursuant hereto, good and valid title to the Units, free
and clear of all liens, encumbrances, security interests, equities, charges or
claims, will pass to the several Underwriters or their designees.
(p) Except as described in the Prospectus, there are no (i) preemptive
rights or other rights to subscribe for or to purchase, (ii) restrictions upon
the voting or transfer of, or (iii) outstanding options or warrants to purchase,
any Units or other interests in the Trust.
(q) There are no contracts, agreements or understandings between the
Company or the Trust and any person granting such person the right to require
the Company or the Trust to file a registration statement under the Securities
Act with respect to any securities of the Company or the Trust owned or to be
owned by such person or to require the Company or the Trust to include such
securities in the securities registered pursuant to the Registration Statement
or in any securities being registered pursuant to any other registration
statement filed by the Company or the Trust under the Securities Act.
(r) None of the formation of the Trust by the execution and delivery of
the Trust Agreement and the transfer of the Net Profits Interests by the Company
to the Trust by the execution and delivery of the Conveyances, the sale of the
Units by the Company hereunder, the compliance by the Statoil Parties and the
Trust with all of the provisions of this Agreement, the Trust Agreement and the
Conveyances and the consummation of the transactions herein contemplated (i)
conflicts or will conflict with or constitutes or will constitute a violation of
the Trust Agreement or the certificate or articles of incorporation or bylaws or
other organizational documents of any of the Statoil Parties or any of their
subsidiaries, (ii) conflicts or will conflict with or constitutes or will
constitute a breach or violation of, or a default under (or an event which, with
notice or lapse of time or both, would constitute such an event), any other
indenture, mortgage, deed of trust, loan agreement, lease or other agreement or
instrument to which any of the Statoil Parties or any of their subsidiaries or
the Trust is a party or by which any of the Statoil Parties or any of their
subsidiaries or the Trust is bound or to which any of the property or assets of
any of the Statoil Parties or any of their subsidiaries or the Net Profit
Interests is subject, (iii) violates or will violate any statute, law, rule or
regulation or any order, judgment, decree or injunction of any court or
governmental agency or body having jurisdiction
-5-
<PAGE> 6
over any of the Statoil Parties or any of their subsidiaries or the Trust or any
of their properties in a proceeding to which any of them or their property is a
party or (iv) will result in the creation or imposition of any lien, charge or
encumbrance upon any property or assets of any of the Statoil Parties or any of
their subsidiaries or the Trust.
(s) No permit, consent, approval, authorization, order, registration,
filing, recordation or qualification of or with any court, governmental agency
or body is or was required in connection with the execution and delivery of, or
the consummation by the Statoil Parties and the Trust of the transactions
contemplated by, this Agreement, the Trust Agreement or the Conveyances, except
as required under the Securities Act, the Securities Exchange Act of 1934, as
amended (the "Exchange Act"), and state securities or "Blue Sky" laws.
(t) All consents, approvals, authorizations and orders necessary for
the transfer of the Net Profits Interests to the Trust as described in the
Prospectus have been obtained and such transfer has not had the effect of
creating any lien, encumbrance, security interest, equity, charge or claim of
any kind in favor of any person with respect to any of the Net Profits Interests
(including any preferential right of purchase, or, with respect to any
properties in which the Company has acted as operator, any right to remove the
Company as operator) except to the extent such rights have been validly waived
in writing.
(u) None of the Statoil Parties nor any of their subsidiaries is in (i)
violation of its certificate or articles of incorporation or bylaws or other
organizational documents, or of any law, statute, ordinance, administrative or
governmental rule or regulation applicable to it or of any order, judgment,
decree or injunction of any court or governmental agency or body having
jurisdiction over it, or (ii) breach, default (or an event which, with notice or
lapse of time or both, would constitute such an event) or violation in the
performance of any obligation, agreement or condition contained in any bond,
debenture, note or any other evidence of indebtedness or in any agreement,
indenture, lease or other instrument to which it is a party or by which it or
any of its properties may be bound. To the knowledge of the Statoil Parties, no
third party to any indenture, mortgage, deed of trust, loan agreement or other
agreement or instrument to which any of the Statoil Parties is a party or by
which any of them is bound or to which any of their properties are subject, is
in default under any such agreement.
(v) Neither the Company nor any of its subsidiaries nor the Underlying
Properties has sustained since the date of the latest audited financial
statements included in the Prospectus any material loss or interference with its
business from fire, explosion, flood or other calamity, whether or not covered
by insurance, or from any labor dispute or court or governmental action, order
or decree, otherwise than as set forth or contemplated in the Prospectus; and,
since the respective dates as of which information is given in the Registration
Statement and the Prospectus, (i) neither the Company nor any of its
subsidiaries or the Trust has incurred any liability or obligation, indirect,
direct or contingent, or entered into any transactions, not in the ordinary
course of business, that, singly or in the aggregate, is material to the Company
and its subsidiaries, taken as a whole, or the Trust, (ii) there has not been
any change in the long-term debt of the Company or any of its subsidiaries or
any change in the number of outstanding Trust Units or (iii) there has not been
any
-6-
<PAGE> 7
material adverse change, or any development involving a prospective material
adverse change, in or affecting the general affairs, management, financial
position, stockholders' equity or results of operations of the Company and its
subsidiaries, taken as a whole, the Trust or the Underlying Properties,
otherwise than as set forth or contemplated in the Prospectus.
(w) The financial statements (including the related notes and
supporting schedules) included in the Registration Statement and the Prospectus
(and any amendment or supplement thereto) present fairly in all material
respects the financial position, results of operations and cash flows of the
entities or properties purported to be shown thereby, at the dates and for the
periods indicated, and have been prepared in conformity with generally accepted
accounting principles applied on a consistent basis throughout the periods
indicated, except to the extent disclosed therein. The pro forma statement of
distributable cash of the Trust included in the Registration Statement and the
Prospectus (and any amendment or supplement thereto) has been prepared in all
material respects in accordance with the applicable accounting requirements of
Article 11 of Regulation S-X of the Commission; the assumptions used in the
preparation of such pro forma financial statement are, in the opinion of the
management of the Statoil Parties, reasonable; and the pro forma adjustments
reflected in such pro forma financial statement have been properly applied to
the historical amounts in compilation of such pro forma financial statement.
(x) Ernst & Young LLP, who have certified certain financial statements
of the Trust, the Company and the Underlying Properties included in the
Prospectus, are independent public accountants as required by the Securities Act
and the Rules and Regulations.
(y) The information supplied by the Company to its independent
petroleum engineering consultants, Ryder Scott Company, L.P., for purposes of
preparing the reserve reports used to calculate estimates of reserves of the
Company, the Underlying Properties and the Net Profits Interest included in the
Prospectus, including, without limitation, information relating to production,
costs of operation and development, current prices for production, agreements
relating to current and future operations and sales of production, was true and
correct in all material respects on the date supplied and was prepared in
accordance with customary industry practices. Ryder Scott Company, L.P. is
independent with respect to the Statoil Parties and the Trust.
(z) The Company has good and marketable title to the Underlying
Properties, free and clear of all liens, claims, security interests or other
encumbrances, except (i) royalties, overriding royalties and other burdens under
oil and gas leases that do not reduce the Company's net revenue interests in the
Underlying Properties below those stated in Ryder Scott Company, L.P.'s reserve
report for the Underlying Properties included in the Prospectus, (ii) easements,
restrictions, rights-of-way and other matters that commonly affect property,
(iii) liens securing taxes and other governmental charges, or claims of
materialmen, mechanics and similar persons, not yet due and payable, (iv) liens
and encumbrances under operating agreements and unitization, pooling and
communitization agreements, declarations and orders, securing payment of amounts
not yet due and payable and of a scope and nature customary in the oil and gas
industry and (v) liens, encumbrances and defects that do not in the aggregate
materially affect the value of the Underlying Properties or materially interfere
with the use made or proposed to be made of such Underlying Properties by the
-7-
<PAGE> 8
Company. All contracts, agreements or underlying leases that comprise a portion
of the Underlying Properties are in full force and effect, and the Company has
paid all royalties, rents and other charges to the extent due and payable
thereunder, is not in default under any of such underlying contracts, agreements
or leases, has received no notice of default from any other party thereto and
knows of no material default by any other party thereto.
(aa) The working interests in oil, gas and mineral leases or mineral
interests which constitute a portion of the Underlying Properties held by the
Company reflect in all material respects the right of the Company to explore or
receive production from such Underlying Properties, and the care taken by the
Company and its subsidiaries with respect to acquiring or otherwise procuring
such leases or mineral interests was generally consistent with standard industry
practices for acquiring or procuring leases and interests therein to explore for
hydrocarbons.
(bb) At each Delivery Date, the Trust will have good and marketable
title to the Net Profits Interests, free and clear of all liens, encumbrances,
security interests, equities, charges or claims, except liens securing taxes and
other governmental charges and liens, encumbrances and defects that do not in
the aggregate materially affect the value of the Net Profits Interests. The
descriptions of the Net Profits Interests in the Conveyances, including the
exhibits thereto, are complete and accurate in all material respects.
(cc) The Company and its subsidiaries maintain insurance covering their
properties, operations, personnel and businesses against such losses and risks
as are reasonably adequate to protect them and their businesses in a manner
consistent with other businesses similarly situated. None of the Company nor its
subsidiaries has received notice from any insurer or agent of such insurer that
substantial capital improvements or other expenditures will have to be made in
order to continue such insurance; and all such insurance is outstanding and duly
in force on the date hereof and will be outstanding and duly in force on each
Delivery Date.
(dd) Other than as set forth in the Prospectus, there are no legal or
governmental proceedings pending to which the Company or any of its subsidiaries
or the Trust is a party or of which any Underlying Property or the Net Profits
Interests is the subject which are required to be described in the Prospectus;
and, to the best of the Company's knowledge, no such proceedings are threatened
or contemplated by governmental authorities or threatened by others; and there
are no agreements, contracts, indentures, leases or other instruments that are
required to be described in the Registration Statement or the Prospectus or to
be filed as an exhibit to the Registration Statement that are not described or
filed as required by the Securities Act.
(ee) Except as described in the Prospectus, no labor dispute by the
employees of the Company or any of its subsidiaries exists or, to the knowledge
of the Company, is imminent which might reasonably be expected to have a
material adverse effect on the condition (financial or other), business,
prospects, properties, net worth or results of operations of the Company or the
Trust.
(ff) Each of the Company and its subsidiaries has filed (or has
obtained extensions with respect to) all material tax returns required to be
filed through the date hereof, which returns are
-8-
<PAGE> 9
complete and correct in all material respects, and has timely paid all taxes
shown to be due pursuant to such returns, other than those (i) which, if not
paid, would not have a material adverse effect on the condition (financial or
other), business, prospects, properties, net worth or results of operations of
the Company and its subsidiaries, taken as a whole, or (ii) which are being
contested in good faith.
(gg) The Company and its subsidiaries have, or at each Delivery Date
will have, such permits, consents, licenses, franchises and authorizations of
governmental or regulatory authorities ("permits") as are necessary to own or
lease their properties and to conduct their business in the manner described in
the Prospectus, subject to such qualifications as may be set forth in the
Prospectus and except for such permits which, if not obtained, would not have,
individually or in the aggregate, a material adverse effect upon the ability of
the Company and its subsidiaries, considered as a whole, to conduct their
businesses in all material respects as currently conducted and as contemplated
by the Prospectus to be conducted; the Company and its subsidiaries have, or at
each Delivery Date will have, fulfilled and performed all their material
obligations with respect to such permits and no event has occurred which allows,
or after notice or lapse of time would allow, revocation or termination thereof
or results in any impairment of the rights of the holder of any such permit,
except for such revocations, terminations and impairments that would not have a
material adverse effect upon the ability of the Company and its subsidiaries
considered as a whole to conduct their businesses in all material respects as
currently conducted and as contemplated by the Prospectus to be conducted,
subject in each case to such qualification as may be set forth in the
Prospectus.
(hh) The Company (i) makes and keeps books, records and accounts,
which, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of assets and (ii) maintains systems of internal accounting
controls sufficient to provide reasonable assurances that (A) transactions are
executed in accordance with management's general or specific authorization; (B)
transactions are recorded as necessary to permit preparation of financial
statements in conformity with generally accepted accounting principles and to
maintain accountability for assets; (C) access to assets is permitted only in
accordance with management's general or specific authorization; and (D) the
recorded accountability for assets is compared with existing assets at
reasonable intervals and appropriate action is taken with respect to any
differences.
(ii) To the knowledge of the Company, neither the Company nor any of
its subsidiaries, nor any director, officer, agent, employee or other person
associated with or acting on behalf of the Company or any of its subsidiaries,
has used any corporate funds for any unlawful contribution, gift, entertainment
or other unlawful expense relating to political activity; made any direct or
indirect unlawful payment to any foreign or domestic government official or
employee from corporate funds; violated or is in violation of any provision of
the Foreign Corrupt Practices Act of 1977; or made any bribe, rebate, payoff,
influence payment, kickback or other unlawful payment.
(jj) The Company has reviewed its operations and that of its
subsidiaries and is in the process of reviewing the relevant operations of third
parties with which the Company or any of its subsidiaries has a material
relationship to evaluate the extent to which the business or operations of the
Company or any of its subsidiaries will be affected by the Year 2000 Problem. As
a result of such review, the Company has no reason to believe, and does not
believe, that the Year 2000 Problem will
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<PAGE> 10
have a material adverse effect on the condition (financial or other), business,
prospects, properties, net worth or results of operations of the Company and its
subsidiaries or result in any material loss or interference with the Company's
business or operations. The "Year 2000 Problem" as used herein means any
significant risk that computer hardware or software used in the receipt,
transmission, processing, manipulation, storage, retrieval, retransmission or
other utilization of data or in the operation of mechanical or electrical
systems of any kind will not, in the case of dates or time periods occurring
after December 31, 1999, function at least as effectively as in the case of
dates or time periods occurring prior to January 1, 2000.
(kk) There has been no storage, disposal, generation, manufacture,
refinement, transportation, handling or treatment of toxic wastes, medical
wastes, hazardous wastes or hazardous substances by the Company or any of its
subsidiaries (or, to the knowledge of the Company, any of their predecessors in
interest) at, upon or from any of the property now or previously owned or leased
by the Company or its subsidiaries in violation of any applicable law,
ordinance, rule, regulation, order, judgment, decree or permit or which would
require remedial action under any applicable law, ordinance, rule, regulation,
order, judgment, decree or permit, except for any violation or remedial action
which would not have, or would not be reasonably likely to have, singularly or
in the aggregate with all such violations and remedial actions, a material
adverse effect on the general affairs, management, financial position,
stockholders' equity or results of operations of the Company and its
subsidiaries; there has been no material spill, discharge, leak, emission,
injection, escape, dumping or release of any kind onto such property or into the
environment surrounding such property of any toxic wastes, medical wastes, solid
wastes, hazardous wastes or hazardous substances due to or caused by the Company
or any of its subsidiaries or with respect to which the Company or any of its
subsidiaries have knowledge, except for any such spill, discharge, leak,
emission, injection, escape, dumping or release which would not have or would
not be reasonably likely to have, singularly or in the aggregate with all such
spills, discharges, leaks, emissions, injections, escapes, dumpings and
releases, a material adverse effect on the general affairs, management,
financial position, stockholders' equity or results of operations of the Company
and its subsidiaries; and their terms "hazardous waster," "toxic wastes,"
"hazardous substances" and "medical wastes" shall have the meanings specified in
any applicable local, state, federal and foreign laws or regulations with
respect to environmental protection.
(ll) Except as described in the Prospectus, there is (i) no action,
suit or proceeding before or by any court, arbitrator or governmental agency,
body or official, domestic or foreign, now pending or, to the knowledge of the
Statoil Parties, threatened, to which any of the Statoil Parties or the Trust is
or may be a party or to which the business or property of any of the Statoil
Parties or the Trust is or may be subject, (ii) no statute, rule, regulation or
order that has been enacted, adopted or issued by any governmental agency or
that has been proposed by any governmental body, and (iii) no injunction,
restraining order or order of any nature issued by a federal or state court or
foreign court of competent jurisdiction to which any of the Statoil Parties or
the Trust is or may be subject, that, in the case of clauses (i), (ii) and (iii)
above, is reasonably expected to (A) singly or in the aggregate have a material
adverse effect on the condition (financial or otherwise), business, prospects,
properties, net worth or results of operations of the Statoil Parties, taken as
a whole, or the Trust or (B) prevent or result in the suspension of the offering
and issuance of the Units.
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<PAGE> 11
(mm) Neither the Company nor the Trust is or, after giving effect to
the offering and sale of Trust Units, will be (i) an "investment company" or a
company "controlled by" an "investment company" as such terms are defined in the
Investment Company Act of 1940, as amended (the "Investment Company Act") or
(ii) a "public utility company," "holding company" or a "subsidiary company" of
a "holding company" or an "affiliate" thereof, under the Public Utility Holding
Company Act of 1935, as amended.
(nn) The Company has not distributed and, prior to the later to occur
of (i) the First Delivery Date and (ii) completion of the distribution of the
Units, will not distribute, any prospectus (as defined under the Securities Act)
in connection with the offering and sale of the Units other than the
Registration Statement, any Preliminary Prospectus, the Prospectus or other
materials, if any, permitted by the Securities Act, including Rule 134 of the
Rules and Regulations.
(oo) The Units have been approved for listing on the New York Stock
Exchange ("NYSE"), subject only to official notice of issuance.
2. Purchase of the Units by the Underwriters. On the basis of the
representations and warranties contained in, and subject to the terms and
conditions of, this Agreement, the Company agrees to sell 7,875,000 Firm Units
to the several Underwriters, and each of the Underwriters, severally and not
jointly, agrees to purchase the number of Firm Units set opposite that
Underwriter's name in Schedule 1 hereto. The respective purchase obligations of
the Underwriters with respect to the Firm Units shall be rounded among the
Underwriters to avoid fractional shares, as the Representatives may determine.
In addition, the Company grants to the Underwriters an option to
purchase up to 1,181,250 Option Units. Such option is granted solely for the
purpose of covering over-allotments in the sale of Firm Units and is exercisable
as provided in Section 4 hereof. Option Units shall be purchased severally for
the account of the Underwriters in proportion to the number of Firm Units set
opposite the names of such Underwriters in Schedule 1 hereto. The respective
purchase obligations of each Underwriter with respect to the Option Units shall
be adjusted by the Representatives so that no Underwriter shall be obligated to
purchase Option Units other than in 100 Unit amounts. The price of both the Firm
Units and any Option Units shall be $_____ per Unit.
The Company shall not be obligated to deliver any of the Units to be
delivered on the First Delivery Date or the Second Delivery Date (as defined in
Section 4), as the case may be, except upon payment for all the Units to be
purchased on such Delivery Date as provided herein.
3. Offering of Units by the Underwriters. Upon authorization by the
Representatives of the release of the Firm Units, the several Underwriters
propose to offer the Firm Units for sale upon the terms and conditions set forth
in the Prospectus.
4. Delivery of and Payment for the Units. Delivery of and payment for
the Firm Units shall be made at the office of Lehman Brothers Inc. at 10:00
A.M., New York City time, on the fourth full business day following the date of
this Agreement or at such other date or place as shall be
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<PAGE> 12
determined by agreement between the Representatives and the Company. This date
and time are sometimes referred to as the "First Delivery Date." On the First
Delivery Date, the Company shall deliver or cause to be delivered certificates
representing the Firm Units to the Representatives for the account of each
Underwriter against payment to or upon the order of the Company of the purchase
price by wire transfer of immediately available funds. Time shall be of the
essence, and delivery at the time and place specified pursuant to this Agreement
is a further condition of the obligation of each Underwriter hereunder. Upon
delivery, the Firm Units shall be registered in such names and in such
denominations as the Representatives shall request in writing not less than two
full business days prior to the First Delivery Date. For the purpose of
expediting the checking and packaging of the certificates for the Firm Units,
the Company shall make the certificates representing the Firm Units available
for inspection by the Representatives in New York, New York, not later than 2:00
P.M., New York City time, on the business day prior to the First Delivery Date.
At any time on or before the thirtieth day after the date of this
Agreement, the option granted in Section 2 may be exercised by written notice
being given to the Company by the Representatives. Such notice shall set forth
the aggregate number of Option Units as to which the option is being exercised,
the names in which the Option Units are to be registered, the denominations in
which the Option Units are to be issued and the date and time, as determined by
the Representatives, when the Option Units are to be delivered; provided,
however, that this date and time shall not be earlier than the First Delivery
Date nor earlier than the second business day after the date on which the option
shall have been exercised nor later than the fifth business day after the date
on which the option shall have been exercised. The date and time the Option
Units are delivered are sometimes referred to as the "Second Delivery Date," and
the First Delivery Date and the Second Delivery Date are sometimes each referred
to as a "Delivery Date."
Delivery of and payment for the Option Units shall be made at the place
specified in the first sentence of the first paragraph of this Section 4 (or at
such other place as shall be determined by agreement between the Representatives
and the Company) at 10:00 A.M., New York City time, on the Second Delivery Date.
On the Second Delivery Date, the Company shall deliver or cause to be delivered
the certificates representing the Option Units to the Representatives for the
account of each Underwriter against payment to or upon the order of the Company
of the purchase price by wire transfer of immediately available funds. Time
shall be of the essence, and delivery at the time and place specified pursuant
to this Agreement is a further condition of the obligation of each Underwriter
hereunder. Upon delivery, the Option Units shall be registered in such names and
in such denominations as the Representatives shall request in the aforesaid
written notice. For the purpose of expediting the checking and packaging of the
certificates for the Option Units, the Company shall make the certificates
representing the Option Units available for inspection by the Representatives in
New York, New York, not later than 2:00 P.M., New York City time, on the
business day prior to the Second Delivery Date.
5. Further Agreements of the Company and the Trust. (a) The Company and
the Trustee, on behalf of the Trust, agree:
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<PAGE> 13
(i) (A) To prepare the Prospectus in a form approved by the
Representatives and to file such Prospectus pursuant to Rule 424(b) under the
Securities Act not later than Commission's close of business on the second
business day following the execution and delivery of this Agreement or, if
applicable, such earlier time as may be required by Rule 430A(a)(3) under the
Securities Act; (B) to make no further amendment or any supplement to the
Registration Statement or to the Prospectus except as permitted herein; (C) to
advise the Representatives, promptly after it receives notice thereof, of the
time when any amendment to the Registration Statement has been filed or becomes
effective or any supplement to the Prospectus or any amended Prospectus has been
filed and to furnish the Representatives with copies thereof; (D) to advise the
Representatives, promptly after it receives notice thereof, of the issuance by
the Commission of any stop order or of any order preventing or suspending the
use of any Preliminary Prospectus or the Prospectus, of the suspension of the
qualification of the Units for offering or sale in any jurisdiction, of the
initiation or threatening of any proceeding for any such purpose or of any
request by the Commission for the amending or supplementing of the Registration
Statement or the Prospectus or for additional information; and (E) in the event
of the issuance of any stop order or of any order preventing or suspending the
use of any Preliminary Prospectus or the Prospectus or suspending any such
qualification, to use promptly its reasonable commercial efforts to obtain its
withdrawal.
(ii) To furnish promptly to each of the Representatives and to counsel
for the Underwriters a signed copy of the Registration Statement as originally
filed with the Commission and of each amendment thereto filed with the
Commission, including all consents and exhibits filed therewith.
(iii) To deliver promptly to the Representatives such number of the
following documents as the Representatives shall reasonably request: (i)
conformed copies of the Registration Statement as originally filed and of each
amendment thereto, but without exhibits, and (ii) each Preliminary Prospectus,
the Prospectus and any amended or supplemented Prospectus; and if the delivery
of a prospectus is required at any time after the Effective Time in connection
with the offering or sale of the Units or any other securities relating thereto
and if at such time any event shall have occurred as a result of which the
Prospectus as then amended or supplemented would include an untrue statement of
a material fact or omit to state any material fact necessary in order to make
the statements therein, in the light of the circumstances under which they were
made when such Prospectus is delivered, not misleading, or, if for any other
reason it shall be necessary to amend or supplement the Prospectus in order to
comply with the Securities Act, to notify the Representatives and, upon their
request, to file such document and to prepare and furnish without charge to each
Underwriter and to any dealer in securities as many copies as the
Representatives may from time to time reasonably request of an amended or
supplemented Prospectus which will correct such statement or omission or effect
such compliance.
(iv) To file promptly with the Commission any amendment to the
Registration Statement or the Prospectus or any supplement to the Prospectus
that may, in the reasonable judgment of the Company or the Representatives, be
required by the Securities Act or requested by the Commission.
(v) Not to (A) file any amendment to the Registration Statement or make
any amendment or supplement to the Prospectus of which Lehman Brothers Inc.
shall not previously have been
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<PAGE> 14
advised or to which the Representatives or their counsel shall reasonably object
in writing after being so advised or (B) so long as, in the opinion of counsel
for the Underwriters, a Prospectus is required to be delivered in connection
with sales by any Underwriter or dealer, file any information, documents or
reports pursuant to the Exchange Act without delivering a copy of such
information, documents or reports to the Representatives prior to or
concurrently with such filing.
(vi) Promptly from time to time to take such action as the
Representatives may reasonably request to qualify the Units for offering and
sale under the securities laws of such jurisdictions as the Representatives may
request and to comply with such laws so as to permit the continuance of sales
and dealings therein in such jurisdictions for as long as may be necessary to
complete the distribution of the Units; provided that in no event shall the
Company be obligated in connection therewith to qualify as a foreign corporation
or to execute a general consent to service of process.
(vii) For a period of 180 days following the date of this Prospectus,
not to, directly or indirectly, (A) offer for sale, sell, pledge or otherwise
dispose of (or enter into any transaction or device which is designed to, or
could be expected to, result in the disposition by any person at any time in the
future of) any Trust Units or any securities that are convertible into, or
exercisable or exchangeable for, or that represent the right to receive, Trust
Units, or sell or grant options, rights or warrants with respect to any Trust
Units or securities that are convertible into, or exercisable or exchangeable
for, or that represent the right to receive, Trust Units, except as disclosed in
the Prospectus, or (B) enter into any swap or other derivatives transaction that
transfers to another, in whole or in part, any of the economic benefits or risks
of ownership of such Trust Units, whether any such transaction described in
clause (A) or (B) above is to be settled by delivery of Trust Units or other
securities, in cash or otherwise, in each case without the prior written consent
of Lehman Brothers Inc.
(viii) To apply the net proceeds from the sale of the Units being sold
by the Company as set forth in the Prospectus.
(ix) To take such steps as shall be necessary to ensure that neither
the Company, any of its subsidiaries or the Trust shall become an "investment
company" within the meaning of such term under the Investment Company Act of
1940 and the rules and regulations of the Commission thereunder.
(x) To timely complete all required filings and otherwise fully comply
in a timely manner with all provisions of the Exchange Act, including the rules
and regulations thereunder, in connection with the registration of the Units
thereunder.
(b) The Trustee, on behalf of the Trust, agrees:
(i) As soon as practicable after the Effective Date (it being
understood that the Trust shall have at least 410 days after the end of the
first full fiscal quarter after the Effective Date) to cause the Trust to make
generally available to holders of Trust Units and to deliver to the
Representatives an earnings statement of the Trust (which need not be audited)
complying with
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<PAGE> 15
Section 11(a) of the Securities Act and the rules and regulations of the
Commission thereunder (including, at the option of the Trustee, Rule 158).
(ii) To cause the Trust to furnish to Trust Unitholders as
soon as practicable after the end of each fiscal year an annual report
(including financial statements of the Trust certified by independent public
accountants) and, as soon as practicable after the end of each of the first
three quarters of each fiscal year (beginning with the fiscal quarter ending
after the effective date of the Registration Statement), to make available to
its Trust Unitholders summary financial information of the Trust for such
quarter in reasonable detail, all as required by the Trust Agreement.
(iii) For a period of five years following the Effective Date,
to cause the Trust to furnish to the Representatives copies of all materials
(financial or other) furnished by the Trust to the holders of Trust Units and
all public reports and all reports and financial statements furnished by the
Trust to the principal national securities exchange upon which the Trust Units
may be listed pursuant to requirements of or agreements with such exchange or to
the Commission pursuant to the Exchange Act or any rule or regulation of the
Commission thereunder.
6. Expenses. The Company agrees to pay (a) the costs incident to the
authorization, issuance, sale and delivery of the Units and any taxes payable in
that connection; (b) the costs incident to the preparation, printing, filing,
delivery and shipping of the Registration Statement and any amendments and
exhibits thereto; (c) the costs of distributing the Registration Statement as
originally filed and each amendment thereto and any post-effective amendments
thereof (including, in each case, exhibits), each Preliminary Prospectus, the
Prospectus and any amendment or supplement to the Prospectus, all as provided in
this Agreement; (d) the costs of producing and distributing this Agreement and
any other related documents in connection with the offering, purchase, sale and
delivery of the Units; (e) the filing fees incident to securing any required
review by the National Association of Securities Dealers, Inc. of the terms of
sale of the Units; (f) any applicable listing or other similar fees; (g) the
fees and expenses of qualifying the Units under the securities laws of the
several jurisdictions as provided in Section 5(e) and of preparing, printing and
distributing a Blue Sky Memorandum (including related fees and expenses of
counsel to the Underwriters); (h) the cost of printing certificates representing
the Units; (i) the costs and charges of any transfer agent or registrar; and (j)
all other costs and expenses incident to the performance of the obligations of
the Company; provided that, except as provided in this Section 6 and in Section
11 the Underwriters shall pay their own costs and expenses, including the costs
and expenses of their counsel, any transfer taxes on the Units which they may
sell and the expenses of advertising any offering of the Units made by the
Underwriters.
7. Conditions of Underwriters' Obligations. The respective obligations
of the Underwriters hereunder are subject to the accuracy, when made and on each
Delivery Date, of the representations and warranties of the Company and the
Trustee contained herein, to the performance by the Company and the Trustee of
their respective obligations hereunder, and to each of the following additional
terms and conditions:
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<PAGE> 16
(a) The Prospectus shall have been filed with the Commission pursuant
to Rule 424(b) within the applicable time period prescribed for such filing by
the rules and regulations under the Act and in accordance with Section 5(a)
hereof; if the Company has elected to rely upon Rule 462(b), the Rule 462(b)
Registration Statement shall have become effective by 10:00 p.m. Washington,
D.C. time on the date of this Agreement; no stop order suspending the
effectiveness of the Registration Statement or any part thereof shall have been
issued and no proceeding for that purpose shall have been initiated or
threatened by the Commission; and any request of the Commission for inclusion of
additional information in the Registration Statement or the Prospectus or
otherwise shall have been complied with.
(b) No Underwriter shall have been advised by the Company or shall have
discovered and disclosed to the Company on or prior to such Delivery Date that
the Registration Statement or the Prospectus or any amendment or supplement
thereto contains an untrue statement of fact which, in the opinion of the
Representatives or counsel to the Underwriters, is material or omits to state a
fact, which, in the opinion of the Representatives or in the opinion of counsel
to the Underwriters, is material and is required to be stated therein or is
necessary to make the statements therein not misleading.
(c) All corporate and trust proceedings and other legal matters
incident to the authorization, form and validity of this Agreement, the Units,
the Registration Statement and the Prospectus, and all other legal matters
relating to this Agreement and the transactions contemplated hereby shall be
reasonably satisfactory in all material respects to counsel for the
Underwriters, and the Company shall have furnished to such counsel all documents
and information that they may reasonably request to enable them to pass upon
such matters.
(d) Andrews & Kurth L.L.P. shall have furnished to the Representatives
their written opinion, as counsel to the Company and the Trust, addressed to the
Underwriters and dated such Delivery Date, in form and substance reasonably
satisfactory to the Representatives, to the effect that:
(i) Each of the Company and Statoil Energy Holdings has been
duly incorporated and is validly existing as a corporation in good
standing under the laws of the State of Delaware, with full corporate
power and authority to own or lease its properties and conduct its
business, in each case in all material respects as described in the
Prospectus.
(ii) Each of the Company and Statoil Energy Holdings has been
duly registered or qualified as a foreign corporation for the
transaction of business and is in good standing under the laws of each
jurisdiction set forth on Exhibit A to such opinion; and, to such
counsel's knowledge, such jurisdictions are the only jurisdictions in
which the character of the business conducted by the Company or Statoil
Energy Holdings or the nature or location of the properties owned or
leased by the Company or Statoil Energy Holdings makes such
registration or qualification necessary, except where the failure to so
register or qualify would not have a material adverse effect on the
condition (financial or other), business, prospects, properties, net
worth or results of operations of the Statoil Parties or the Trust.
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<PAGE> 17
(iii) Statoil Energy has been duly incorporated and is validly
existing as a corporation in good standing under the laws of the
Commonwealth of Virginia, with full corporate power and authority to
own or lease its properties and conduct its business, in each case in
all material respects as described in the Prospectus.
(iv) Statoil Energy has been duly registered or qualified as a
foreign corporation for the transaction of business and is in good
standing under the laws of each jurisdiction set forth on Exhibit A to
such opinion; and, to such counsel's knowledge, such jurisdictions are
the only jurisdictions in which the character of the business conducted
by Statoil Energy or the nature or location of the properties owned or
leased by it makes such registration or qualification necessary, except
where the failure to so register or qualify would not have a material
adverse effect on the condition (financial or otherwise), business,
prospects, properties, net worth or results of operations of Statoil
Parties or the Trust.
(v) Statoil Energy owns 100% of the outstanding common stock
of Statoil Energy Holdings; such common stock has been duly authorized
and validly issued and is fully paid and nonassessable; and Statoil
Energy owns such common stock free and clear of all liens,
encumbrances, security interests, charges or claims (A) in respect of
which a financing statement under the Uniform Commercial Code of the
State of Delaware or the Commonwealth of Virginia naming Statoil Energy
is on file in the office of the Secretary of State of the State of
Delaware or the Commonwealth of Virginia or (b) otherwise known to such
counsel, without independent investigation, other than those created by
or arising under the Delaware General Corporation Law (the "DGCL").
(vi) Statoil Energy Holdings owns 100% of the outstanding
common stock of the Company; such common stock has been duly authorized
and validly issued and is fully paid and nonassessable; and Statoil
Energy Holdings owns such common stock free and clear of all liens,
encumbrances, security interests, charges or claims (A) in respect of
which a financing statement under the Uniform Commercial Code of the
State of Delaware or the Commonwealth of Virginia naming Statoil Energy
Holdings is on file in the office of the Secretary of State of the
States of Delaware or the Commonwealth of Virginia or (b) otherwise
known to such counsel, without independent investigation, other than
those created by or arising under the DGCL.
(vii) This Agreement, the Trust Agreement and the Conveyances
have been duly authorized, executed and delivered by the Statoil
Parties.
(viii) The Trust Agreement is the valid and legally binding
obligation of the Company enforceable against the Company in accordance
with its terms, except as such enforceability may be limited by (A)
applicable bankruptcy, insolvency, fraudulent transfer, reorganization,
moratorium or similar laws relating to or affecting creditors' rights
generally and by general principles of equity (regardless of whether
such enforceability is considered in a proceeding in equity or at law)
and (B) public policy, applicable law relating to fiduciary duties and
indemnification and an implied covenant of good faith and fair dealing.
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<PAGE> 18
(ix) The Company owns the Trust Units free and clear of all
liens, encumbrances, security interests, charges or claims (A) in
respect of which a financing statement under the Uniform Commercial
Code of the State of Delaware naming the Company as debtor is on file
in the office of the Secretary of State of the State of Delaware or (B)
otherwise known to such counsel, without independent investigation,
other than those created by or arising under the DGCL.
(x) The Company has all requisite power and authority to sell
the Units in accordance with and upon the terms set forth in this
Agreement. Upon delivery to the Underwriters of certificates evidencing
the Units issued in the name of the Underwriters or their designees and
payment by the Underwriters of the purchase price for the Units, the
Underwriters will acquire the Units free of any adverse claim (as such
term is defined in Article 8 of the New York Uniform Commercial Code),
assuming that the Underwriters are acting in good faith and without
notice of any adverse claim.
(xi) Except as described in the Prospectus, there are no (A)
preemptive rights or other rights to subscribe for or to purchase, (B)
restrictions upon the voting or transfer of, or (C) outstanding options
or warrants to purchase, any Units or other interests in the Trust
pursuant to any agreement or instrument known to such counsel to which
the Company or the Trust is a party or by which any one of them may be
bound. To such counsel's knowledge, there are no contracts, agreements
or understandings between the Company or the Trust and any person
granting such person the right to require the Company or the Trust to
file a registration statement under the Securities Act with respect to
any securities of the Company or the Trust owned or to be owned by such
person or to require the Company or the Trust to include such
securities in the securities registered pursuant to the Registration
Statement or in any securities being registered pursuant to any other
registration statement filed by the Company or the Trust under the
Securities Act.
(xii) None of the formation of the Trust by the execution and
delivery of the Trust Agreement and the transfer of the Net Profits
Interests by the Company to the Trust by the execution and delivery of
the Conveyances, the sale of the Units by the Company hereunder, the
compliance by the Statoil Parties with all of the provisions of this
Agreement, the Trust Agreement and the Conveyances and the consummation
of the transactions herein contemplated (A) constitutes or will
constitute a violation of the certificate or articles of incorporation
or bylaws or other organizational documents of any of the Statoil
Parties or any of their subsidiaries, (B) constitutes or will
constitute a breach or violation of, or a default under (or an event
which, with notice or lapse of time or both, would constitute such an
event), any agreement filed as an exhibit to the Registration Statement
(other than the Trust Agreement) or any credit agreement, note
agreement, indenture, promissory note or other agreement evidencing or
governing indebtedness of any of the Statoil Parties or any of their
subsidiaries, (C) violates or will violate any statute, law, rule or
regulation or any order, judgment, decree or injunction of any court or
governmental agency or body known to such counsel having jurisdiction
over any of the Statoil Parties or any of their subsidiaries or any of
their properties in a proceeding to which any of them or their property
is a party or (D)
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<PAGE> 19
results or will result in the creation or imposition of any lien,
charge or encumbrance upon any property or assets of any of the Statoil
Parties or any of their subsidiaries.
(xiii) No permit, consent, approval, authorization, order,
registration, filing, recordation or qualification of or with any
court, governmental agency or body is or was required in connection
with the execution and delivery of, or the consummation by the Statoil
Parties and the Trust of the transactions contemplated by, this
Agreement, the Trust Agreement or the Conveyances, except as required
under the Securities Act, the Exchange Act and state securities or
"Blue Sky" laws.
(xiv) The statements in the Registration Statement and the
Prospectus under the captions "The Trust," "The Underlying Properties
-- Sale and Abandonment of Underlying Properties; Sale of Net Profits
Interests," "The Underlying Properties -- Title to Properties,"
"Computation of Net Proceeds," "Description of the Trust Agreement,"
and "Description of the Trust Units," insofar as they constitute
descriptions of agreements or refer to statements of law or legal
conclusions, are accurate and complete in all material respects, and
the Trust Units conform in all material respects to the description
thereof contained in the Registration Statement and the Prospectus.
(xv) The opinion of Andrews & Kurth L.L.P. that is filed as
Exhibit 8.1 to the Registration Statement is confirmed and the
Underwriters may rely upon such opinion as if it were addressed to
them.
(xvi) The Registration Statement was declared effective under
the Securities Act on October ___, 1999; to the knowledge of such
counsel, no stop order suspending the effectiveness of the Registration
Statement has been issued and no proceedings for that purpose have been
instituted or threatened by the Commission; and any required filing of
the Prospectus pursuant to Rule 424(b) has been made in the manner and
within the time period required by such Rule.
(xvii) The Registration Statement and the Prospectus (except
for the financial statements and the notes and the schedules thereto,
the reserve information contained therein and the other financial,
statistical and accounting data included in the Registration Statement
or the Prospectus, as to which such counsel need not express any
opinion) comply as to form in all material respects with the
requirements of the Act and the rules and regulations promulgated
thereunder.
(xviii) To the knowledge of such counsel, (A) there is no
legal or governmental proceeding pending or threatened to which any of
the Statoil Parties or the Trust is a party or to which any of their
respective properties is subject that is required to be disclosed in
the Prospectus and is not so disclosed and (B) there are no agreements,
contracts or other documents to which any of the Statoil Parties or the
Trust is a party that are required to be
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described in the Registration Statement or the Prospectus or to be
filed as exhibits to the Registration Statement that are not described
or filed as required.
(xix) None of the Statoil Parties is an "investment company"
as such term is defined in the Investment Company Act of 1940, as
amended.
In addition, such counsel shall state that they have participated in
conferences with officers and other representatives of the Statoil Parties and
the independent public accountants of the Company and the Trust and your
representatives, at which the contents of the Registration Statement and the
Prospectus and related matters were discussed, and although such counsel has not
independently verified, is not passing on, and is not assuming any
responsibility for the accuracy, completeness or fairness of the statements
contained in, the Registration Statement and the Prospectus (except to the
extent specified in the foregoing opinion), no facts have come to such counsel's
attention that lead such counsel to believe that the Registration Statement
(other than (i) the financial statements included therein, including the notes
and schedules thereto and the auditors' reports thereon, (ii) the reserve report
and other reserve information included therein and (iii) the other financial and
accounting data included therein, as to which such counsel need not comment), as
of its effective date contained an untrue statement of a material fact or
omitted to state a material fact required to be stated therein or necessary to
make the statements therein not misleading, or that the Prospectus (other than
(i) the financial statements included therein, including the notes and schedules
thereto and the auditors' reports thereon, (ii) the reserve report and other
reserve information included therein and (iii) the other financial and
accounting data included therein, as to which such counsel need not comment), as
of its issue date and each Delivery Date contained an untrue statement of a
material fact or omitted to state a material fact necessary to make the
statements therein, in the light of the circumstances under which they were
made, not misleading.
In rendering such opinion, such counsel may (A) rely in
respect of matters of fact upon certificates of officers and employees of the
Statoil Parties and upon information obtained from public officials, (B) assume
that all documents submitted to them as originals are authentic, that all copies
submitted to them conform to the originals thereof, and that the signatures on
all documents examined by them are genuine, (C) state that their opinion is
limited to federal laws, the Delaware Business Trust Act (as defined in Section
7(e)), the DGCL and the laws of the States of New York and Texas, (D) with
respect to the opinions expressed in paragraphs (ii) and (iv) above as to the
due registration or qualification as a foreign corporation of each of the
Statoil Parties, state that such opinions are based upon the opinions of Vorys,
Sater, Seymour, and Pease LLP and Goodwin and Goodwin provided pursuant to
Section 7 (g) below and upon certificates of foreign qualification or
registration provided by the Secretaries of State of the States of Delaware,
Indiana, Kentucky, Michigan, Mississippi, New Mexico, New York, Ohio,
Pennsylvania, Virginia and West Virginia (each of which shall be dated as of a
date not more than fourteen days prior to the Closing Date and shall be provided
to you), (E) state that they express no opinion with respect to the title of any
of the Underlying Properties or the Net Profits Interest and (F) state that they
express no opinion with respect to state or local taxes or tax statutes to which
any of the Statoil Parties or the Trust may be subject.
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<PAGE> 21
(e) Richards, Layton & Finger, P.A. shall have furnished to the
Representatives their written opinion, as counsel to the Trust, addressed to the
Underwriters and dated such Delivery Date, in form and substance reasonably
satisfactory to the Representatives, to the effect that:
(i) The Trust has been duly formed and is validly existing as
a business trust within the meaning of the Delaware Business Trust Act
(12 Del. Code Section 3801, et seq. (the "Delaware Business Trust
Act")) and has full trust power and authority to own or lease its
properties as described in the Prospectus.
(ii) There are 10,500,000 Trust Units representing units of
undivided beneficial interest in the Trust authorized and issued under
the Trust Agreement, all of which have been duly authorized and validly
issued and are fully paid and nonassessable and conform to the
descriptions thereof in the Prospectus.
(iii) Each of the Trust Agreement and the Conveyances,
assuming the due authorization, execution and delivery thereof by the
Company, is a valid and legally binding obligation of the Trustee and
the Delaware Trustee enforceable against the Trustee and the Delaware
Trustee in accordance with their respective terms, except as such
enforceability may be limited by (A) applicable bankruptcy, insolvency,
fraudulent transfer, reorganization, moratorium or similar laws
relating to or affecting creditors' rights generally and by general
principles of equity (regardless of whether such enforceability is
considered in a proceeding in equity or at law) and (B) public policy,
applicable law relating to fiduciary duties and indemnification and an
implied covenant of good faith and fair dealing.
(iv) All action of the Trustee, the Delaware Trustee and the
Trust required under the Delaware Business Trust Act and the Trust
Agreement with respect to the authorization and issuance of the Trust
Units has been taken; Unitholders (as defined in the Trust Agreement)
are entitled to the benefits of the Trust Agreement; except as
described in the Prospectus under the heading "Description of the Trust
Agreement -- Conditional Right of Repurchase," the issuance of such
Trust Units is not subject to any preemptive rights or similar rights
arising under the Delaware Business Trust Act or the Trust Agreement.
(v) None of the formation of the Trust by the execution and
delivery of the Trust Agreement and the transfer of the Net Profits
Interests by the Company to the Trust by the execution and delivery of
the Conveyances, the sale of the Units by the Company hereunder, the
compliance by the Statoil Parties with all of the provisions of this
Agreement, the Trust Agreement and the Conveyances and the consummation
by the Statoil Parties, the Trustee and the Delaware Trustee of the
transactions herein contemplated (A) constitutes or will constitute a
violation of the Trust Agreement or the Trust's certificate of trust,
(B) constitutes or will constitute a breach or violation of, or a
default under (or an event which, with notice or lapse of time or both,
would constitute such an event), any credit agreement, note agreement,
indenture, promissory note or any other agreement known to such counsel
to which the Trust is a party or by which the Trust is bound, (C)
violates or will violate any statute, law, rule or regulation or any
order, judgment, decree or injunction of any court or governmental
agency
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<PAGE> 22
or body known to such counsel having jurisdiction over the Trust or (D)
results or will result in the creation or imposition of any lien,
charge or encumbrance upon any property or assets of any of the Trust.
(vi) Each Unitholder shall be entitled to the same limitation
on personal liability as is extended to stockholders of private
corporations for profit under the DGCL.
(vii) The Trust Agreement complies in all respects with the
requirements of the Delaware Business Trust Act; the conditional right
of repurchase of the Company provided for in Section 9.04 of the Trust
Agreement is permitted by and lawful under the Delaware Business Trust
Act and compliance by the Trustee with such Section 9.04 will not
violate any fiduciary duty requirements of the Trustee under applicable
provisions of Delaware law, including, without limitation, the Delaware
Business Trust Act; compliance by the Trustee and the Delaware Trustee
with Article XI of the Trust Agreement providing for arbitration will
not violate any fiduciary duty requirements of the Trustee or the
Delaware Trustee under applicable provisions of Delaware law,
including, without limitation, the Delaware Business Trust Act.
(viii) Assuming that the Trustee conducts all of its
activities with respect to the Trust at its offices in Forth Worth,
Texas, (A) the Trustee is not required to qualify to do business as a
trust company under 5 Del. Code Ann. Section 901, et seq. solely by
reason of acting as a trustee of the Trust, (B) no consent, approval,
authorization or filing is required under any other law or any rule or
regulation of the State of Delaware in order to permit the Trustee to
act as Trustee of the Trust, and (C) the compliance by the Trustee with
the provisions of the Trust Agreement will not result in the violation
of any statute, rule or regulation of the State of Delaware applicable
to the Trust.
(ix) The specimen temporary certificate for the Trust Units
and the specimen definitive certificate for the Trust Units are in
proper legal form.
In rendering such opinion, such counsel may (A) rely in respect of matters of
fact upon certificates of officers and employees of the Statoil Parties and upon
information obtained from public officials, (B) assume that all documents
submitted to them as originals are authentic, that all copies submitted to them
conform to the originals thereof, and that the signatures on all documents
examined by them are genuine and (C) state that their opinion is limited to the
laws of the State of Delaware.
(f) Kerry W. Eckstein shall have furnished to the Representatives his
written opinion, as General Counsel of the Company, addressed to the
Underwriters and dated such Delivery Date, in form and substance reasonably
satisfactory to the Representatives, to the effect that:
(i) None of the formation of the Trust by the execution and
delivery of the Trust Agreement and the transfer of the Net Profits
Interests by the Company to the Trust by the execution and delivery of
the Conveyances, the sale of the Units by the Company hereunder, the
compliance by the Statoil Parties and the Trust with all of the
provisions of this
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<PAGE> 23
Agreement, the Trust Agreement and the Conveyances and the consummation
of the transactions herein contemplated (A) constitutes or will
constitute a breach or violation of, or a default under (or an event
which, with notice or lapse of time or both, would constitute such an
event), any indenture, mortgage, deed of trust, loan agreement, lease
or other agreement or instrument known to such counsel to which any of
the Statoil Parties or any of their subsidiaries or the Trust is a
party or by which any of the Statoil Parties or any of their
subsidiaries or the Trust is bound or to which any of the property or
assets of any of the Statoil Parties or any of their subsidiaries or
the Net Profit Interests is subject (other than any agreement filed as
an exhibit to the Registration Statement or any credit agreement, note
agreement, indenture, promissory note or other agreement evidencing or
governing indebtedness of any of the Statoil Parties or their
subsidiaries) or (B) violates or will violate any order, judgment,
decree or injunction of any court or governmental agency or body known
to such counsel directed to any of the Statoil Parties or any of their
subsidiaries or the Trust or any of their properties in a proceeding to
which any of them or their property is a party.
(ii) All consents, approvals, authorizations and orders
necessary for the transfer of the Net Profits Interests to the Trust as
described in the Prospectus have been obtained and such transfer has
not had the effect of creating any lien, encumbrance, security
interest, equity, charge or claim of any kind in favor of any person
with respect to any of the Net Profits Interests (including any
preferential right of purchase, or, with respect to any properties in
which the Company has acted as operator, any right to remove the
Company as operator) except to the extent such rights have been validly
waived in writing.
(iii) To the knowledge of such counsel, none of the Statoil
Parties nor any of their subsidiaries is in (A) violation of its
certificate or articles of incorporation or bylaws or other
organizational documents, or of any law, statute, ordinance,
administrative or governmental rule or regulation applicable to it or
of any order, judgment, decree or injunction of any court or
governmental agency or body having jurisdiction over it, or (B) breach,
default (or an event which, with notice or lapse of time or both, would
constitute such an event) or violation in the performance of any
obligation, agreement or condition contained in any bond, debenture,
note or any other evidence of indebtedness or in any agreement,
indenture, lease or other instrument to which it is a party or by which
it or any of its properties may be bound, which breach, default or
violation would, if continued, have a material adverse effect on the
condition (financial or other), business, prospects, properties, net
worth or results of operations of the Statoil Parties, taken as a
whole, or the Trust or could materially impair the ability of any of
the Statoil Parties or the Trust to perform its obligations under this
Agreement, the Trust Agreement or the Conveyances.
(iv) To the knowledge of such counsel, the Company and its
subsidiaries have such permits, consents, licenses, franchises and
authorizations of governmental or regulatory authorities ("permits") as
are necessary to own or lease their properties and to conduct their
business in the manner described in the Prospectus, subject to such
qualifications as may be set forth in the Prospectus and except for
such permits which, if not obtained, would not have, individually or in
the aggregate, a material adverse effect upon the ability of the
Company and
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<PAGE> 24
its subsidiaries, considered as a whole, to conduct their businesses in
all material respects as currently conducted and as contemplated by the
Prospectus to be conducted; and, to the knowledge of such counsel,
neither the Company nor its subsidiaries has received any notice of
proceedings relating to the revocation or modification of any such
permits which, individually or in the aggregate, if the subject of an
unfavorable decision, ruling or finding, would reasonably be expected
to have a material adverse effect upon the operations conducted by the
Trust.
(v) Except as described in the Prospectus, to the knowledge of
such counsel, there is no litigation, proceeding or governmental
investigation pending or threatened against any of the Statoil Parties
or their subsidiaries or the Trust which, if adversely determined to
such party, is reasonably likely to have a material adverse effect on
the financial condition, business, properties or results of operations
of the Trust.
In addition, such counsel shall state that he has participated in
conferences with officers and other representatives of the Statoil Parties and
the independent public accountants of the Company and the Trust and your
representatives, at which the contents of the Registration Statement and the
Prospectus and related matters were discussed, and although such counsel has not
independently verified, is not passing on, and is not assuming any
responsibility for the accuracy, completeness or fairness of the statements
contained in, the Registration Statement and the Prospectus, no facts have come
to such counsel's attention that lead such counsel to believe that the
Registration Statement (other than (i) the financial statements included
therein, including the notes and schedules thereto and the auditors' reports
thereon, (ii) the reserve report and other reserve information included therein
and (iii) the other financial and accounting data included therein, as to which
such counsel need not comment), as of its effective date contained an untrue
statement of a material fact or omitted to state a material fact required to be
stated therein or necessary to make the statements therein not misleading, or
that the Prospectus (other than (i) the financial statements included therein,
including the notes and schedules thereto and the auditors' reports thereon,
(ii) the reserve report and other reserve information included therein and (iii)
the other financial and accounting data included therein, as to which such
counsel need not comment), as of its issue date and each Delivery Date contained
an untrue statement of a material fact or omitted to state a material fact
necessary to make the statements therein, in the light of the circumstances
under which they were made, not misleading.
In rendering such opinion, such counsel may (A) rely in
respect of matters of fact upon certificates of officers and employees of the
Statoil Parties and upon information obtained from public officials, (B) assume
that all documents submitted to him as originals are authentic, that all copies
submitted to him conform to the originals thereof, and that the signatures on
all documents examined by him are genuine, (C) state that such opinions are
limited to federal laws, the DGCL and the laws of the State of Virginia, (D)
state that he expresses no opinion with respect to the title of any of the
Underlying Properties or the Net Profits Interest and (E) state that he
expresses no opinion with respect to state or local taxes or tax statutes.
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<PAGE> 25
(g) Each of Vorys, Sater, Seymour, and Pease LLP, special local counsel
for the Company and the Trust in the State of Kentucky, and Goodwin and Goodwin,
special local counsel for the Company and the Trust in the State of West
Virginia, shall have furnished to the Representatives its written opinion,
addressed to the Underwriters and dated such Delivery Date, in form and
substance reasonably satisfactory to the Representatives, to the effect that:
(i) The Company has been duly registered or qualified as a
foreign corporation for the transaction of business and is in good
standing under the laws of [insert applicable state].
(ii) Neither the Trust, the Trustee nor the Delaware Trustee
is required to qualify to transact business or appoint an agent for
service of process in [insert applicable state] as a result of the
ownership, operation or activities of the Trust, the Trustee or the
Delaware Trustee with respect to the Trust, and the activities of the
Trustee and the Delaware Trustee pursuant to the Trust Agreement will
not require the appointment of an ancillary trustee in the State of
[insert applicable state].
(iii) The [applicable] Conveyance, assuming the due
authorization, execution and delivery thereof by the parties thereto,
is the valid and legally binding obligation of the Company enforceable
against the Company in accordance with its terms, except as such
enforceability of the [applicable] Conveyance may be limited by (A)
applicable bankruptcy, insolvency, fraudulent transfer, reorganization,
moratorium or similar laws relating to or affecting creditors' rights
generally and by general principles of equity (regardless of whether
such enforceability is considered in a proceeding in equity or at law)
and (B) public policy, applicable law relating to fiduciary duties and
indemnification and an implied covenant of good faith and fair dealing.
A court of competent jurisdiction of [insert applicable state] should
give effect to the choice of law provisions of the [applicable]
Conveyance.
(iv) The Net Profits Interests constitute real property
interests under the laws of [insert applicable state].
(v) The [applicable] Conveyance (A) has been properly filed of
record and recorded in the appropriate real property records in [insert
applicable state], (B) is adequate and sufficient to legally convey to
the Trustee the Net Profits Interests in [insert applicable state], and
(C) constitutes, in [insert applicable state], a perfected Conveyance
and effective notice of the Net Profits Interests in the Underlying
Properties located in [insert applicable state], which is and will be
valid and binding against third parties subsequently acquiring
interests in the Underlying Properties and is and will be superior to
all future liens and encumbrances on the Underlying Properties (except
for such liens and encumbrances for taxes and assessments not yet due
and payable, and liens and encumbrances under operating agreements and
unitization, pooling and communitization agreements, declarations and
orders, securing payments of amounts not yet due and payable). No
actions other than those described above are necessary to convey the
Net Profits Interests in [insert applicable state] and to publish
notice thereof.
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<PAGE> 26
(vi) A beneficial owner of a Trust Unit will not be subject to
personal liability under state and local laws in [insert applicable
state] by virtue of said ownership, including liability regulating the
discharge of materials into the environment or otherwise relating to
the protection of the environment.
(vii) There is no restriction on the ownership of interests in
minerals or Units by non-U.S. residents under the laws of the State of
[insert applicable state].
(viii) None of the formation of the Trust by the execution and
delivery of the Trust Agreement and the transfer of the Net Profits
Interests by the Company to the Trust by the execution and delivery of
the Conveyances, the sale of the Units by the Company hereunder, the
compliance by the Statoil Parties and the Trust with all of the
provisions of this Agreement, the Trust Agreement and the Conveyances
and the consummation of the transactions herein contemplated results or
will result in any violation of any statute, law, rule or regulation or
any order, judgment, decree or injunction of any court or governmental
agency or body in the State of [insert applicable state] known to such
counsel directed to any of the Statoil Parties or any of their
subsidiaries or the Trust or any of their properties in a proceeding to
which any of them or their property is a party.
(ix) No permit, consent, approval, authorization, order,
registration, filing, recordation or qualification of or with any
court, governmental agency or body of the State of [insert applicable
state] is or was required (A) to permit the Trustee to act as trustee
with respect to the Underlying Properties located in [insert applicable
state] or (B) in connection with the execution and delivery of, or the
consummation by the Statoil Parties and the Trust of the transactions
contemplated by, this Agreement, the Trust Agreement or the
Conveyances, except for such permits, consents, approvals and similar
authorizations required under state securities or "Blue Sky" laws.
(x) The income from the Net Profits Interests received by the
Trust will not be subject to taxation at the Trust level by [insert
applicable state] or any political subdivision thereof. A Unitholder
will be subject to taxation by [insert applicable state] with respect
to income from the Net Profits Interests or ownership of Trust Units
and is required to report such income to [insert applicable state] only
if the amount of gross income attributable to sources in [insert
applicable state][during a fiscal year] exceeds $____________.
(xi) The Trust is not required to withhold [insert applicable
state] taxes from distributions to Unitholders.
(xii) A non-resident holder of a Trust Unit will not be
subject to inheritance or gift taxation, intestate succession, elective
shares of community property or require the filing of ancillary probate
proceedings in the State of [insert applicable state] solely by reason
of ownership of Trust Units.
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<PAGE> 27
In rendering such opinion, such counsel may (A) rely in respect of
matters of fact upon certificates of officers and employees of the Statoil
Parties and the Trust and upon information obtained from public officials, (B)
assume that all documents submitted to them as originals are authentic, that all
copies submitted to them conform to the originals thereof, and that the
signatures on all documents examined by them are genuine, (C) state that such
opinions are limited to federal laws and the laws of the State of [insert
applicable state], excepting therefrom municipal and local ordinances and
regulations, (D) state that they express no opinion with respect to the title of
any of the Underlying Properties or the Net Profits Interest and (E) state that
they express no opinion with respect to state or local taxes or tax statutes to
which any of the Statoil Parties may be subject.
In rendering such opinion, such counsel shall state that (A) Andrews &
Kurth L.L.P. is hereby authorized to rely upon such opinion letter in connection
with the transactions contemplated by this Agreement as if such opinion letter
were addressed and delivered to them on the date hereof and (B) subject to the
foregoing, such opinion letter may be relied upon only by the Underwriters and
its counsel in connection with the transactions contemplated by this Agreement
and no other use or distribution of this opinion letter may be made without such
counsel's prior written consent.
(h) Vinson & Elkins L.L.P., counsel for the Trustee and the Delaware
Trustee, shall have furnished to the Representatives their written opinion,
addressed to the Underwriters and dated such Delivery Date, in form and
substance reasonably satisfactory to the Representatives, to the effect that:
(i) Each of the Trustee and the Delaware Trustee is a national
banking association authorized and empowered to act as trustee of the
Trust pursuant to the Trust Agreement, and no consent, approval,
authorization or filing is required under any law, rule or regulation
of the State of Delaware or of the United States of America in order to
permit the Trustee or the Delaware Trustee to act as trustee of the
Trust.
(ii) The Trust Agreement has been executed and delivered by
each of the Trustee and the Delaware Trustee and, assuming the due
authorization, execution and delivery thereof by the Company, is a
valid and binding obligation of each of the Trustee and the Delaware
Trustee, enforceable against the Trustee and the Delaware Trustee in
accordance with its terms; provided that the enforceability of the
Trust Agreement may be limited by (A) applicable bankruptcy,
insolvency, fraudulent transfer, reorganization, moratorium or similar
laws relating to or affecting creditors' rights generally and by
general principles of equity (regardless of whether such enforceability
is considered in a proceeding in equity or at law) and (B) public
policy, applicable law relating to fiduciary duties and indemnification
and an implied covenant of good faith and fair dealing.
(i) Baker & Botts, L.L.P., counsel for the Underwriters, shall have
furnished to you such opinion or opinions, dated such Delivery Date, with
respect to the issuance and sale of the Units, the Registration Statement, the
Prospectus and other related matters as the Representatives may reasonably
request, and such counsel shall have received such papers and information as
they may reasonably request to enable them to pass upon such matters.
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<PAGE> 28
(j) The Company shall have furnished to the Representatives a
certificate, dated such Delivery Date, executed on behalf of the Company by the
chief executive officer and the chief financial officer of the Company, to the
effect that:
(i) The representations and warranties of the Company
contained in this Agreement are true and correct, as if made at and as
of such Delivery Date, and the Company have complied with all the
agreements and satisfied all the conditions on their part to be
complied with or satisfied at or prior to such Delivery Date.
(ii) No stop order suspending the effectiveness of the
Registration Statement has been issued, and no proceeding for that
purpose has been initiated or threatened by the Commission.
(iii) They have carefully examined the Registration Statement
and the Prospectus, and any amendments or supplements thereto, and, in
their opinion (A) as of the Effective Date, the Registration Statement
and Prospectus did not include any untrue statement of a material fact
and did not omit to state a material fact required to be stated therein
not misleading, and (B) since the Effective Date no event has occurred
which should have been set forth in an amendment or supplement to the
Registration Statement or the Prospectus which has not been so set
forth.
(iv) No event contemplated by Section 7(p) in respect of the
Company, the Trust, or the Underlying Properties shall have occurred.
(k) The Trustee shall have furnished to the Representatives a
certificate, dated such Delivery Date, executed by a duly authorized officer of
the Trustee, representing and warranting to each of the Underwriters that:
(i) The Trustee is a national banking association authorized
and empowered to act as trustee of the Trust pursuant to the Trust
Agreement, and no consent, approval, authorization or filing is
required under any law, rule or regulation of the State of Delaware or
of the United States of America in order to permit the Trustee to act
as trustee of the Trust.
(ii) The Trust Agreement has been executed and delivered by
the Trustee and, assuming the due authorization, execution and delivery
thereof by the Company, is a valid and binding obligation of the
Trustee, enforceable against the Trustee in accordance with its terms,
except as such enforceability may be limited by (A) applicable
bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium
or similar laws relating to or affecting creditors' rights generally
and by general principles of equity (regardless of whether such
enforceability is considered in a proceeding in equity or at law) and
(B) public policy, applicable law relating to fiduciary duties and
indemnification and an implied covenant of good faith and fair dealing.
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<PAGE> 29
(iii) There are 10,500,000 Trust Units authorized and
outstanding under the Trust Agreement, all of which have been properly
issued in accordance with the Trust Agreement; certificates
representing the Trust Units have been duly executed by the Trustee;
and holders of certificates representing the Trust Units are entitled
to the benefits of the Trust Agreement.
(iv) Since the date the Trust was formed through each Delivery
Date, except as may otherwise be disclosed in the Registration
Statement and the Prospectus, the Trustee has not on behalf of the
Trust (A) incurred any liability or obligation, indirect, direct or
contingent, or entered into any transactions not in the ordinary course
of business, (B) issued or granted any Trust Units or (C) made any
distribution to the holders of Trust Units.
(v) There is no litigation, proceeding or governmental
investigation pending or, to the knowledge of the Trustee, threatened
to which the Trust is a party.
(l) The Delaware Trustee shall have furnished to the Representatives a
certificate, dated such Delivery Date, executed by a duly authorized officer of
the Delaware Trustee, representing and warranting to each of the Underwriters
that:
(i) The Delaware Trustee is a national banking association
authorized and empowered to act as trustee of the Trust pursuant to the
Trust Agreement, and no consent, approval, authorization or filing is
required under any law, rule or regulation of the State of Delaware or
of the United States of America in order to permit the Delaware Trustee
to act as trustee of the Trust.
(ii) The Trust Agreement has been executed and delivered by
the Delaware Trustee and, assuming the due authorization, execution and
delivery thereof by the Company, is a valid and binding obligation of
the Delaware Trustee, enforceable against the Delaware Trustee in
accordance with its terms, except as such enforceability may be limited
by (A) applicable bankruptcy, insolvency, fraudulent transfer,
reorganization, moratorium or similar laws relating to or affecting
creditors' rights generally and by general principles of equity
(regardless of whether such enforceability is considered in a
proceeding in equity or at law) and (B) public policy, applicable law
relating to fiduciary duties and indemnification and an implied
covenant of good faith and fair dealing.
(iii) Since the date the Trust was formed through each
Delivery Date, except as may otherwise be disclosed in the Registration
Statement and the Prospectus, the Delaware Trustee has not on behalf of
the Trust (A) incurred any liability or obligation, indirect, direct or
contingent, or entered into any transactions not in the ordinary course
of business, (B) issued or granted any Trust Units or (C) made any
distribution to the holders of Trust Units.
(iv) There is no litigation, proceeding or governmental
investigation pending or, to the knowledge of the Delaware Trustee,
threatened to which the Trust is a party.
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<PAGE> 30
(m) At the time of execution of this Agreement, the Representatives
shall have received from Ernst & Young LLP a letter, in form and substance
satisfactory to the Representatives, addressed to the Underwriters and dated the
date hereof (i) confirming that they are independent public accountants within
the meaning of the Securities Act and are in compliance with the applicable
requirements relating to the qualification of accountants under Rule 2-01 of
Regulation S-X of the Commission, (ii) stating, as of the date hereof (or, with
respect to matters involving changes or developments since the respective dates
as of which specified financial information is given in the Prospectus, as of a
date not more than five days prior to the date hereof), the conclusions and
findings of such firm with respect to the financial information and other
matters ordinarily covered by accountants' "comfort letter" to underwriters in
connection with registered public offerings.
(n) With respect to the letter of Ernst & Young referred to in the
preceding paragraph and delivered to the Representatives concurrently with the
execution of this Agreement (the "initial letter"), the Company shall have
furnished to the Representatives a letter (the "bring-down letter") of such
accountants, addressed to the Underwriters and dated such Delivery Date (i)
confirming that they are independent public accountants within the meaning of
the Securities Act and are in compliance with the applicable requirements
relating to the qualification of accountants under Rule 2-01 of Regulation S-X
of the Commission, (ii) stating, as of the date of the bring-down letter (or,
with respect to matters involving changes or developments since the respective
dates as of which specified financial information is given in the Prospectus, as
of a date not more than five days prior to the date of the bring-down letter),
the conclusions and findings of such firm with respect to the financial
information and other matters covered by the initial letter and (iii) confirming
in all material respects the conclusions and findings sets forth in the initial
letter.
(o) The Company shall have furnished or caused to be furnished to the
Representatives a letter from Ryder Scott Company, L.P., addressed to the
Underwriters and dated the respective date of delivery in form and substance
satisfactory to you.
(p) (i) Neither the Company nor any of its subsidiaries, taken
together, the Trust nor the Underlying Properties shall have sustained since the
date of the latest audited financial statements included in the Prospectus any
loss or interference with its business by fire, flood, explosion or other
calamity, whether or not covered by insurance, or from any labor dispute or
court or governmental action, order or decree, otherwise than as set forth or
contemplated in the Prospectus nor (ii) since such date there shall not have
been any change in the capital stock, short-term debt or long-term debt of the
Company, its subsidiaries or the Trust or any change, or any development
involving a prospective change, in or affecting the general affairs, management,
financial position, stockholders' equity or results of operations of the
Company, its subsidiaries or the Trust, otherwise than as set forth or
contemplated in the Prospectus, the effect of which, in any such case described
in clause (i) or (ii), is, in the judgment of the Representatives, so material
and adverse as to make it impracticable or inadvisable to proceed with the
public offering or the delivery of the Units being delivered on such Delivery
Date on the terms and in the manner contemplated in the Prospectus.
(q) Subsequent to the execution and delivery of this Agreement there
shall not have occurred any of the following: (i) trading in securities
generally on the New York Stock Exchange
-30-
<PAGE> 31
or the American Stock Exchange or in the over-the-counter market, or trading in
any securities of the Company or the Trust on any exchange or in the
over-the-counter market, shall have been suspended or minimum prices shall have
been established on any such exchange or such market by the Commission, by such
exchange or by any other regulatory body or governmental authority having
jurisdiction, (ii) a banking moratorium shall have been declared by federal or
state authorities, (iii) the United States shall have become engaged in
hostilities, there shall have been an escalation in hostilities involving the
United States or there shall have been a declaration of a national emergency or
war by the United States or (iv) there shall have occurred such a material
adverse change in general economic, political or financial conditions (or the
effect of international conditions on the financial markets in the United States
shall be such) as to make it, in the judgment of a majority in interest of the
several Underwriters, impracticable or inadvisable to proceed with the public
offering or delivery of the Units being delivered on such Delivery Date on the
terms and in the manner contemplated in the Prospectus.
(r) The New York Stock Exchange shall have approved the Trust Units for
listing, subject only to official notice of issuance.
(s) The Company shall have complied with the provisions of Section
5(a)(iii) hereof with respect to the furnishing of Prospectuses on the New York
business day next succeeding the date of this Agreement.
(t) The Company and the Trust shall have furnished the Representatives
such additional documents and certificates as the Representatives or counsel for
the Underwriters may reasonably request.
8. Indemnification and Contribution.
(a) The Company and the Trust (solely from the assets of the Trust and
without liability or obligation of the Trustee or any Unitholder), jointly and
severally, shall indemnify and hold harmless each Underwriter, its officers and
employees and each person, if any, who controls any Underwriter within the
meaning of the Securities Act, from and against any loss, claim, damage or
liability, joint or several, or any action in respect thereof (including, but
not limited to, any loss, claim, damage, liability or action relating to
purchases and sales of Units), to which that Underwriter, officer, employee or
controlling person may become subject, under the Securities Act or otherwise,
insofar as such loss, claim, damage, liability or action arises out of, or is
based upon, (i) any untrue statement or alleged untrue statement of a material
fact contained in any Preliminary Prospectus, the Registration Statement or the
Prospectus or in any amendment or supplement thereto, (ii) the omission or
alleged omission to state in any Preliminary Prospectus, the Registration
Statement or the Prospectus, or in any amendment or supplement thereto, any
material fact required to be stated therein or necessary to make the statements
therein not misleading or (iii) any act or failure to act or any alleged act or
failure to act by any Underwriter in connection with, or relating in any manner
to, the Units or the offering contemplated hereby, and which is included as part
of or referred to in any loss, claim, damage, liability or action arising out of
or based upon matters covered by clause (i) or (ii) above (provided that neither
the Company nor the Trust shall be liable under this clause (iii) to
-31-
<PAGE> 32
the extent that it is determined in a final judgment by a court of competent
jurisdiction that such loss, claim, damage, liability or action resulted
directly from any such acts or failures to act undertaken or omitted to be taken
by such Underwriter through its gross negligence or willful misconduct), and
shall reimburse each Underwriter and each such officer, employee or controlling
person promptly upon demand for any legal or other expenses reasonably incurred
by that Underwriter, officer, employee or controlling person in connection with
investigating or defending or preparing to defend against any such loss, claim,
damage, liability or action as such expenses are incurred; provided, however,
that neither the Company nor the Trust shall be liable in any such case to the
extent that any such loss, claim, damage, liability or action arises out of, or
is based upon, any untrue statement or alleged untrue statement or omission or
alleged omission made in any Preliminary Prospectus, the Registration Statement
or the Prospectus, or in any such amendment or supplement, in reliance upon and
in conformity with written information concerning such Underwriter furnished to
the Company through the Representatives by or on behalf of any Underwriter
specifically for inclusion therein which information consists solely of the
information specified in Section 8(e). The foregoing indemnity agreement is in
addition to any liability which the Company and the Trust may otherwise have to
any Underwriter or to any officer, employee or controlling person of that
Underwriter.
(b) Each Underwriter, severally and not jointly, shall indemnify and
hold harmless the Company, the Trust and the Trustee, their officers and
employees, each of their directors (including any person who, with his or her
consent, is named in the Registration Statement as about to become a director of
the Company), and each person, if any, who controls the Company, the Trust or
the Trustee within the meaning of the Securities Act, from and against any loss,
claim, damage or liability, joint or several, or any action in respect thereof,
to which the Company and the Trust or any such director, officer or controlling
person may become subject, under the Securities Act or otherwise, insofar as
such loss, claim, damage, liability or action arises out of, or is based upon,
(i) any untrue statement or alleged untrue statement of a material fact
contained in any Preliminary Prospectus, the Registration Statement or the
Prospectus or in any amendment or supplement thereto, or (ii) the omission or
alleged omission to state in any Preliminary Prospectus, the Registration
Statement or the Prospectus, or in any amendment or supplement thereto, any
material fact required to be stated therein or necessary to make the statements
therein not misleading, but in each case only to the extent that the untrue
statement or alleged untrue statement or omission or alleged omission was made
in reliance upon and in conformity with written information concerning such
Underwriter furnished to the Company, the Trust or the Trustee through the
Representatives by or on behalf of that Underwriter specifically for inclusion
therein, and shall reimburse the Company, the Trust and the Trustee and any such
director, officer or controlling person for any legal or other expenses
reasonably incurred by the Company, the Trust or the Trustee or any such
director, officer or controlling person in connection with investigating or
defending or preparing to defend against any such loss, claim, damage, liability
or action as such expenses are incurred. The foregoing indemnity agreement is in
addition to any liability which any Underwriter may otherwise have to the
Company, the Trust or the Trustee or any such director, officer, employee or
controlling person.
(c) Promptly after receipt by an indemnified party under this Section 8
of notice of any claim or the commencement of any action, the indemnified party
shall, if a claim in respect thereof is to be made against the indemnifying
party under this Section 8, notify the indemnifying party in
-32-
<PAGE> 33
writing of the claim or the commencement of that action; provided, however, that
the failure to notify the indemnifying party shall not relieve it from any
liability which it may have under this Section 8 except to the extent it has
been materially prejudiced by such failure, and, provided further, that the
failure to notify the indemnifying party shall not relieve it from any liability
which it may have to an indemnified party otherwise than under this Section 8.
If any such claim or action shall be brought against an indemnified party, and
it shall notify the indemnifying party thereof, the indemnifying party shall be
entitled to participate therein and, to the extent that it wishes, jointly with
any other similarly notified indemnifying party, to assume the defense thereof
with counsel reasonably satisfactory to the indemnified party. After notice from
the indemnifying party to the indemnified party of its election to assume the
defense of such claim or action, the indemnifying party shall not be liable to
the indemnified party under this Section 8 for any legal or other expenses
subsequently incurred by the indemnified party in connection with the defense
thereof other than reasonable costs of investigation; provided, however, that
any indemnified party shall have the right to employ separate counsel in any
such action and participate in the defense thereof, but the fees and expenses of
such counsel shall be at the expense of such indemnified party unless (i) the
employment of such counsel has been specifically authorized in writing by the
indemnifying party, (ii) the indemnifying party shall have failed to assume the
defense and employ counsel or (iii) the named parties to any such action
(including any impleaded parties) include both such indemnified party and the
indemnifying party and such indemnified party shall have been advised by such
counsel that there may be one or more legal defenses available to it which are
different from or additional to those available to the indemnifying party (in
which case the indemnifying party shall not have the right to assume the defense
of such action on behalf of such indemnified party and the fees and expenses of
such separate counsel shall be paid by the indemnifying party). No indemnifying
party shall, in connection with any one such action or proceeding or separate
but substantially similar or related actions or proceedings in the same
jurisdiction arising out of the same general allegations or circumstances, be
liable for the reasonable fees and expenses of more than one separate firm of
attorneys (in addition to any local counsel) at any time for such indemnified
party, which firm shall be designated by the indemnified party. No indemnifying
party shall (i) without the prior written consent of the indemnified parties
(which consent shall not be unreasonably withheld), settle or compromise or
consent to the entry of any judgment with respect to any pending or threatened
claim, action, suit or proceeding in respect of which indemnification or
contribution may be sought hereunder (whether or not the indemnified parties are
actual or potential parties to such claim or action) unless such settlement,
compromise or consent includes an unconditional release of each indemnified
party from all liability arising out of such claim, action, suit or proceeding,
or (ii) be liable for any settlement of any such action effected without its
written consent (which consent shall not be unreasonably withheld), but if
settled with the consent of the indemnifying party or if there be a final
judgment of the plaintiff in any such action, the indemnifying party agrees to
indemnify and hold harmless any indemnified party from and against any loss or
liability by reason of such settlement or judgment.
(d) If the indemnification provided for in this Section 8 shall for any
reason be unavailable to or insufficient to hold harmless an indemnified party
under Section 8(a) or 8(b) in respect of any loss, claim, damage or liability,
or any action in respect thereof, referred to therein, then each indemnifying
party shall, in lieu of indemnifying such indemnified party, contribute to the
amount paid or payable by such indemnified party as a result of such loss,
claim, damage or liability, or action
-33-
<PAGE> 34
in respect thereof, (i) in such proportion as shall be appropriate to reflect
the relative benefits received by the Company and the Trust, on the one hand,
and the Underwriters on the other from the offering of the Units or (ii) if the
allocation provided by clause (i) above is not permitted by applicable law, in
such proportion as is appropriate to reflect not only the relative benefits
referred to in clause (i) above but also the relative fault of the Company and
the Trust, on the one hand, and the Underwriters on the other, with respect to
the statements or omissions which resulted in such loss, claim, damage or
liability, or action in respect thereof, as well as any other relevant equitable
considerations. The relative benefits received by the Company and the Trust, on
the one hand, and the Underwriters on the other, with respect to such offering
shall be deemed to be in the same proportion as the total net proceeds from the
offering of the Units purchased under this Agreement (before deducting expenses)
received by the Company, on the one hand, and the total underwriting discounts
and commissions received by the Underwriters with respect to the Units purchased
under this Agreement, on the other hand, bear to the total gross proceeds from
the offering of the Units under this Agreement, in each case as set forth in the
table on the cover page of the Prospectus. The relative fault shall be
determined by reference to whether the untrue or alleged untrue statement of a
material fact or omission or alleged omission to state a material fact relates
to information supplied by the Company and the Trust or the Underwriters, the
intent of the parties and their relative knowledge, access to information and
opportunity to correct or prevent such statement or omission. The Company and
the Trust and the Underwriters agree that it would not be just and equitable if
contributions pursuant to this Section 8 were to be determined by pro rata
allocation (even if the Underwriters were treated as one entity for such
purpose) or by any other method of allocation which does not take into account
the equitable considerations referred to herein. The amount paid or payable by
an indemnified party as a result of the loss, claim, damage or liability, or
action in respect thereof, referred to above in this Section 8 shall be deemed
to include, for purposes of this Section 8(d), any legal or other expenses
reasonably incurred by such indemnified party in connection with investigating
or defending any such action or claim. Notwithstanding the provisions of this
Section 8(d), no Underwriter shall be required to contribute any amount in
excess of the amount by which the total price at which the Units underwritten by
it and distributed to the public was offered to the public exceeds the amount of
any damages which such Underwriter has otherwise paid or becomes liable to pay
by reason of any untrue or alleged untrue statement or omission or alleged
omission. No person guilty of fraudulent misrepresentation (within the meaning
of Section 11(f) of the Securities Act) shall be entitled to contribution from
any person who was not guilty of such fraudulent misrepresentation. The
Underwriters' obligations to contribute as provided in this Section 8(d) are
several in proportion to their respective underwriting obligations and not
joint.
(e) The Underwriters severally confirm and the Company and the Trust
acknowledge that the statements with respect to the public offering of the Units
by the Underwriters set forth on the cover page of the Prospectus, the
information in the chart in the first paragraph under the caption "Underwriting"
in the Prospectus, the concession and reallowance figures appearing in the
fourth paragraph under the caption "Underwriting" in the Prospectus and the
statements in the eighth, ninth, tenth, eleventh, twelfth, thirteenth (to the
extent relating to the Underwriters), fourteenth and sixteenth paragraphs under
the caption "Underwriting" in the Prospectus are correct and constitute the only
information concerning such Underwriters furnished in writing to the Company or
the Trust by or on behalf of the Underwriters specifically for inclusion in the
Registration Statement and the Prospectus.
-34-
<PAGE> 35
9. Defaulting Underwriters.
If, on either Delivery Date, any Underwriter defaults in the
performance of its obligations under this Agreement, the remaining
non-defaulting Underwriters shall be obligated to purchase the Units which the
defaulting Underwriter agreed but failed to purchase on such Delivery Date in
the respective proportions which the number of Firm Units set opposite the name
of each remaining non-defaulting Underwriter in Schedule 1 hereto bears to the
total number of Firm Units set opposite the names of all the remaining
non-defaulting Underwriters in Schedule 1 hereto; provided, however, that the
remaining non-defaulting Underwriters shall not be obligated to purchase any of
the Units on such Delivery Date if the total number of Units which the
defaulting Underwriter or Underwriters agreed but failed to purchase on such
date exceeds 9.09% of the total number of Units to be purchased on such Delivery
Date, and any remaining non-defaulting Underwriter shall not be obligated to
purchase more than 110% of the number of the Units which it agreed to purchase
on such Delivery Date pursuant to the terms of Section 2. If the foregoing
maximums are exceeded, the remaining non-defaulting Underwriters, or those other
underwriters satisfactory to the Representatives who so agree, shall have the
right, but shall not be obligated, to purchase, in such proportion as may be
agreed upon among them, all the Units to be purchased on such Delivery Date. If
the remaining Underwriters or other underwriters satisfactory to the
Representatives do not elect to purchase the Units which the defaulting
Underwriter or Underwriters agreed but failed to purchase on such Delivery Date,
this Agreement (or, with respect to the Second Delivery Date, the obligation of
the Underwriters to purchase, and of the Company to sell, the Option Units)
shall terminate without liability on the part of any non-defaulting Underwriter,
the Company or the Trust except that the Company will continue to be liable for
the payment of expenses to the extent set forth in Sections 6 and 11. As used in
this Agreement, the term "Underwriter" includes, for all purposes of this
Agreement unless the context requires otherwise, any party not listed in
Schedule 1 hereto who, pursuant to this Section 9, purchases Firm Units which a
defaulting Underwriter agreed but failed to purchase.
Nothing contained herein shall relieve a defaulting Underwriter of any
liability it may have to the Company for damages, including expenses paid by the
Company pursuant to Sections 6 and 11, caused by its default. If other
underwriters are obligated or agree to purchase the Units of a defaulting or
withdrawing Underwriter, either the Representatives or the Company may postpone
the Delivery Date for up to seven full business days in order to effect any
changes that in the opinion of counsel for the Company or counsel for the
Underwriters may be necessary in the Registration Statement, the Prospectus or
in any other document or arrangement.
10. Termination. The obligations of the Underwriters hereunder may be
terminated by the Representatives by notice given to and received by the Company
prior to delivery of and payment for the Firm Units if, prior to that time, any
of the events described in Section 7(p) or Section 7(q) shall have occurred or
if the Underwriters shall decline to purchase the Units for any reason permitted
under this Agreement.
11. Reimbursement of Underwriters' Expenses. If the Company shall fail
to tender the Units for delivery to the Underwriters by reason of any failure,
refusal or inability on the part of the Company or the Trust to perform any
agreement on its part to be performed, or because any other
-35-
<PAGE> 36
condition of the Underwriters' obligations hereunder required to be fulfilled by
the Company or the Trust is not fulfilled, the Company and the Trust will
reimburse the Underwriters for all reasonable out-of-pocket expenses (including
fees and disbursements of counsel) incurred by the Underwriters in connection
with this Agreement and the proposed purchase of the Units, and upon demand the
Company and the Trust shall pay the full amount thereof to the Representatives.
If this Agreement is terminated pursuant to Section 9 by reason of the default
of one or more Underwriters, neither the Company nor the Trust shall be
obligated to reimburse any defaulting Underwriter on account of those expenses.
12. Notices, etc. Any notice, consent, request, instruction, approval
and other communication provided for herein shall be in writing, shall be
delivered or sent by mail, telex or facsimile transmission and shall be deemed
validly given, made or served (a) on the date on which it is delivered
personally with receipt acknowledged, (b) five business days after it is sent by
registered or certified mail (receipt requested and postage prepaid), (c) one
business day after it is sent by overnight courier (charges prepaid) or (d) on
the same business day when sent before 5:00 p.m., recipient's time (and on the
next business day when sent after 5:00 p.m., recipient's time) by telex or
telecopier, transmission confirmed and charges prepaid. Such notices shall be in
writing, and
(i) if to the Company, shall be addressed to the Company at 2800
Eisenhower Avenue, Alexandria, Virginia, 22314, Attention: President.
(ii) if to the Trust, shall be addressed to Bank One Texas, N.A., 500
Throckmorton, Suite 801, Fort Worth, Texas 76102, Attention: Corporate Trust
Department.
(iii) if to the Underwriters, such notice shall be addressed to the
Representatives in care of Lehman Brothers Inc., 3 World Financial Center, 11th
Floor, New York, New York 10285-1100, Attention: Syndicate Department (Fax:
212/526-6588), with a copy, in the case of any notice pursuant to Section 8(c),
to the Director of Litigation, Office of the General Counsel, Lehman Brothers
Inc., 3 World Financial Center, 10th Floor, New York, New York 10285; provided,
however, that any notice to an Underwriter pursuant to Section 8(c) shall be
delivered or sent by mail, telex or facsimile transmission to such Underwriter
at its address set forth in its acceptance telex to the Representatives, which
address will be supplied to any other party hereto by the Representatives upon
request. Any such statements, requests, notices or agreements shall take effect
at the time of receipt thereof. The Company shall be entitled to act and rely
upon any request, consent, notice or agreement given or made on behalf of the
Underwriters by Lehman Brothers Inc. on behalf of the Representatives.
13. Persons Entitled to Benefit of Agreement. This Agreement shall
inure to the benefit of and be binding upon the Underwriters, the Company, the
Trust and their respective successors. This Agreement and the terms and
provisions hereof are for the sole benefit of only those persons, except that
(a) the representations, warranties, indemnities and agreements of the Company
and the Trust contained in this Agreement shall also be deemed to be for the
benefit of the person or persons, if any, who control any Underwriter within the
meaning of Section 15 of the Securities Act and (b) the indemnity agreement of
the Underwriters contained in Section 8(b) of this Agreement shall be deemed to
be for the benefit of directors of the Company, officers of the Company who have
signed
-36-
<PAGE> 37
the Registration Statement and any person controlling any of the Company and the
Trust within the meaning of Section 15 of the Securities Act. Nothing in this
Agreement is intended or shall be construed to give any person, other than the
persons referred to in this Section 13, any legal or equitable right, remedy or
claim under or in respect of this Agreement or any provision contained herein.
14. Survival. The respective indemnities, representations, warranties
and agreements of the Company, the Trust and the Underwriters contained in this
Agreement or made by or on behalf on them, respectively, pursuant to this
Agreement, shall survive the delivery of and payment for the Units and shall
remain in full force and effect, regardless of any investigation made by or on
behalf of any of them or any person controlling any of them.
15. Definition of the Terms "Business Day" and "Subsidiary". For
purposes of this Agreement, (a) "business day" means any day on which the NYSE
is open for trading, and (b) "subsidiary" has the meaning set forth in Rule 405
of the Rules and Regulations.
16. Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF NEW YORK.
17. Counterparts. This Agreement may be executed in one or more
counterparts and, if executed in more than one counterpart, the executed
counterparts shall each be deemed to be an original but all such counterparts
shall together constitute one and the same instrument.
18. Headings. The headings herein are inserted for convenience of
reference only and are not intended to be part of, or to affect the meaning or
interpretation of, this Agreement.
-37-
<PAGE> 38
If the foregoing correctly sets forth the agreement among the Company,
Statoil Energy, Statoil Energy Holdings and the Underwriters, please indicate
your acceptance in the space provided for that purpose below.
Very truly yours,
EASTERN STATES OIL & GAS, INC..
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
STATOIL ENERGY, INC.
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
STATOIL ENERGY HOLDINGS, INC.
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
APPALACHIAN NATURAL GAS TRUST
By: Bank One Texas, N.A., Trustee
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
-38-
<PAGE> 39
Accepted as of the date hereof:
By: LEHMAN BROTHERS INC.
By:
---------------------------------
Authorized Representative
For themselves and as
Representatives of the
several Underwriters named
in Schedule 1 hereto
By: LEHMAN BROTHERS INC.
By:
---------------------------------
Authorized Representative
-39-
<PAGE> 40
SCHEDULE I
<TABLE>
<CAPTION>
NUMBER OF
OPTIONAL
UNITS TO BE
TOTAL NUMBER OF PURCHASED IF
FIRM UNITS MAXIMUM OPTION
UNDERWRITER TO BE PURCHASED EXERCISED
- ------------------------------------------------------------------- --------------- -------------------
<S> <C> <C>
Lehman Brothers Inc................................................
Salomon Smith Barney Inc...........................................
PaineWebber Incorporated...........................................
CIBC World Markets Corp. ..........................................
Credit Suisse First Boston Corporation.............................
Dain Rauscher Wessels
a division of Dain Rauscher Incorporated.......................
Donaldson, Lufkin & Jenrette Securities Corporation................
A.G. Edwards & Sons, Inc. .........................................
MCDONALD INVESTMENTS INC...........................................
--------------- -------------------
--------------- -------------------
TOTAL......................................................... 7,875,000 1,181,250
</TABLE>
<PAGE> 1
EXHIBIT 4.1.2
CERTIFICATE OF AMENDMENT
TO
CERTIFICATE OF TRUST
OF
APPALACHIAN BASIN ROYALTY TRUST
This Certificate of Amendment to that certain Certificate of Trust of
Appalachian Basin Royalty Trust dated as of August 19, 1999, is filed by the
undersigned trustees pursuant to Section 3810(b) of the Delaware Business Trust
Act.
1. Name. The name of the business trust is Appalachian Basin Royalty Trust.
2. Amendment. The Certificate of Trust is hereby amended to change the
name of the business trust to:
APPALACHIAN NATURAL GAS TRUST
IN WITNESS WHEREOF, the undersigned trustee has executed this Certificate
of Amendment as of October 4, 1999.
Bank One Delaware, Inc., as Trustee
By: /s/ SANDRA L. CARUBA
-------------------------------------
Name: Sandra L. Caruba
Title: Vice President
/s/ KERRY W. ECKSTEIN
----------------------------------------
Kerry W. Eckstein, as Trustee
<PAGE> 1
EXHIBIT 4.2
RESTATED TRUST AGREEMENT
OF
APPALACHIAN NATURAL GAS TRUST
THIS RESTATED TRUST AGREEMENT (this "Restated Trust
Agreement") of APPALACHIAN NATURAL GAS TRUST is made as of October 4, 1999, by
and among Eastern States Oil & Gas, Inc., a Delaware corporation, as sponsor
(the "Sponsor"), and Bank One Delaware, Inc., a Delaware corporation, as
trustee, and Kerry W. Eckstein, as trustee (jointly, the "Trustees").
Recitals
1. The Sponsor and the Trustees entered into the Trust Agreement
of Appalachian Basin Royalty Trust as of August 18, 1999 (the
"Trust Agreement");
2. The Trustees filed the Certificate of Trust with the Delaware
Secretary of State on August 19, 1999; and
3. The Sponsor and the Trustees now desire to restate the Trust
Agreement to reflect a change in the name of the trust to
"Appalachian Natural Gas Trust" to more clearly reflect the
business of the trust.
The Sponsor and the Trustees hereby agree as follows:
1. The trust created by the Trust Agreement shall hereafter be
known as "Appalachian Natural Gas Trust" (the "Trust"), in which name the
Trustees or the Sponsor, to the extent provided herein, may conduct the
business of the Trust, make and execute contracts, and sue and be sued.
2. The Sponsor hereby assigns, transfers, conveys and sets over to
the Trust the sum of $1000.00. Such amount shall constitute the initial trust
estate. It is the intention of the parties hereto that the Trust created
hereby constitute a business trust under Chapter 38 of Title 12 of the Delaware
Code, 12 Del. C. Section 3801, et seq. (the "Business Trust Act"), and that
this document constitute the governing instrument of the Trust. The Trustees
are hereby authorized and directed to execute and file a certificate of trust
with the Secretary of State of the State of Delaware in such form as the
Trustees may approve.
3. The Sponsor and the Trustees will enter into an amended and
restated Trust Agreement satisfactory to each such party to provide for the
contemplated operation of the Trust created hereby and the issuance of the
trust securities referred to therein. Prior to the execution and delivery of
such amended and restated Trust Agreement, the Trustees shall not have any duty
<PAGE> 2
or obligation hereunder or with respect to the trust estate, except as
otherwise contemplated by this Trust Agreement, required by applicable law or
as may be necessary to obtain prior to such execution and delivery any
licenses, consents or approvals required by applicable law or otherwise.
Notwithstanding the foregoing, the Trustees may take all actions deemed proper
as are necessary to effect the transactions contemplated herein.
4. The Sponsor, as sponsor of the Trust, is hereby authorized, in
its sole discretion, (i) to prepare and file with the Securities and Exchange
Commission (the "SEC") and to execute, in the case of the 1933 Act Registration
Statement and 1934 Act Registration Statement (as herein defined), on behalf of
the Trust, (a) a Registration Statement (the "1933 Act Registration
Statement"), including all pre-effective and post-effective amendments thereto,
relating to the registration under the Securities Act of 1933, as amended (the
"1933 Act"), of the trust securities of the Trust, (b) any preliminary
prospectus or prospectus or supplement thereto relating to the trust securities
of the Trust required to be filed pursuant to the 1933 Act, and (c) a
Registration Statement on Form 8-A or other appropriate form (the "1934 Act
Registration Statement"), including all pre-effective and post-effective
amendments thereto, relating to the registration of the trust securities of the
Trust under the Securities Exchange Act of 1934, as amended; (ii) if and at
such time as determined by the Sponsor, to file with the New York Stock
Exchange Inc. ("NYSE"), or other exchange, or the National Association of
Securities Dealers ("NASD"), and execute on behalf of the Trust a listing
application and all other applications, statements, certificates, agreements
and other instruments as shall be necessary or desirable to cause the trust
securities of the Trust to be listed on the NYSE or such other exchange, or the
NASD's Nasdaq National Market; (iii) to file and execute on behalf of the
Trust, such applications, reports, surety bonds, irrevocable consents,
appointments of attorney for service of process and other papers and documents
that shall be necessary or desirable to register the trust securities of the
Trust under the securities or "blue sky" laws of such jurisdictions as the
Sponsor, on behalf of the Trust, may deem necessary or desirable; (iv) to
execute and deliver letters or documents to, or instruments for filing with, a
depository relating to the trust securities of the Trust; (v) to execute,
deliver and perform on behalf of the Trust one or more conveyances pursuant to
which the Sponsor, or one or more of its subsidiaries, conveys to the Trust a
net profits interest in certain oil and gas properties located in Kentucky and
West Virginia; and (vi) to execute, deliver and perform on behalf of the Trust
an underwriting agreement with one or more underwriters relating to the
offering of the trust securities of the Trust.
In the event that any filing referred to in this Section 4 is
required by the rules and regulations of the SEC, the NYSE or other exchange,
NASD, or state securities or "blue sky" laws to be executed on behalf of the
Trust by the Trustees, the Trustees, in their capacity as trustees of the
Trust, are hereby authorized to join in any such filing and to execute on
behalf of the Trust any and all of the foregoing, it being understood that the
Trustees, in their capacity as trustees of the Trust, shall not be required to
join in any such filing or execute on behalf of the Trust any such document
unless required by the rules and regulations of the Commission, the NYSE or
other exchange, NASD, or state securities or "blue sky" laws.
<PAGE> 3
5. This Restated Trust Agreement may be executed in one or more
counterparts.
6. The number of trustees of the Trust initially shall be two and
thereafter the number of trustees of the Trust shall be such number as shall be
fixed from time to time by a written instrument signed by the Sponsor which may
increase or decrease the number of trustees of the Trust; provided, however,
that to the extent required by the Business Trust Act, one trustee of the Trust
shall either be a natural person who is a resident of the State of Delaware or,
if not a natural person, an entity that has its principal place of business in
the State of Delaware and otherwise meets the requirements of applicable law.
Subject to the foregoing, the Sponsor is entitled to appoint or remove without
cause any trustee of the Trust at any time. Any trustee of the Trust may
resign upon 30 days' prior notice to the Sponsor.
7. The Sponsor hereby agrees to (i) reimburse the Trustees for
all reasonable expenses (including reasonable fees and expenses of counsel and
other experts) and (ii) indemnify, defend and hold harmless the Trustees and
any of the officers, directors, employees and agents of the trustees (the
"Indemnified Persons") from and against any and all losses, damages,
liabilities, claims, actions, suits, costs, expenses, disbursements (including
the reasonable fees and expenses of counsel), taxes and penalties of any kind
and nature whatsoever (collectively, "Expenses"), to the extent that such
Expenses arise out of or are imposed upon or asserted at any time against such
Indemnified Persons with respect to the performance of this Trust Agreement,
the creation, operation or termination of the Trust or the transactions
contemplated hereby; provided, however, that the Sponsor shall not be required
to indemnify any Indemnified Person for any Expenses that are a result of the
willful misconduct, bad faith or gross negligence of such Indemnified Person.
8. The Trust may be dissolved and terminated before the issuance
of the trust securities of the Trust at the election of the Sponsor.
9. This Restated Trust Agreement shall be governed by, and
construed in accordance with, the laws of the State of Delaware (without regard
to conflict of laws principles).
10. Bank One Delaware, Inc., in its capacity as Trustee hereunder,
shall not have any of the powers or duties of the trustees set forth herein,
except as required under the Business Trust Act, and shall be a Trustee
hereunder for the sole and limited purpose of fulfilling the requirements of
Section 3807(a) of the Business Trust Act.
(Remainder of page intentionally left blank)
<PAGE> 4
IN WITNESS WHEREOF, the parties hereto have caused this
Restated Trust Agreement to be duly executed as of the day and year first above
written.
EASTERN STATES OIL & GAS, INC.,
as Sponsor
By: /s/ STEVENS V. GILLESPIE
---------------------------------------
Name: Stevens V. Gillespie
Title: Senior Vice President and Chief
Financial Officer
BANK ONE DELAWARE, INC.,
as Trustee
By: /s/ SANDRA L. CARUBA
---------------------------------------
Name: Sandra L. Caruba
Title: Vice President
/s/ KERRY W. ECKSTEIN
------------------------------------------
Kerry W. Eckstein, as Trustee
<PAGE> 1
EXHIBIT 4.3
================================================================================
FORM OF
AMENDED AND RESTATED
TRUST AGREEMENT
OF
APPALACHIAN NATURAL GAS TRUST
------------------
DATED AS OF SEPTEMBER 1, 1999
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<S> <C>
ARTICLE I
DEFINITIONS
SECTION 1.01 Definitions..................................................................................1
ARTICLE II
NAME AND PURPOSE OF THE TRUST; DECLARATION OF TRUST
SECTION 2.01 Name.........................................................................................6
SECTION 2.02 Purposes.....................................................................................7
SECTION 2.03 Transfer of Trust Property to the Trust; Closing Matters.....................................8
SECTION 2.04 Nature of the Trust..........................................................................9
SECTION 2.05 Principal Office and Delaware Trustee........................................................9
ARTICLE III
ADMINISTRATION OF THE TRUST AND POWERS OF THE TRUSTEE
AND THE DELAWARE TRUSTEE
SECTION 3.01 General Authority............................................................................9
SECTION 3.02 Limited Power of Disposition................................................................10
SECTION 3.03 No Power to Engage in Business or Make Investments..........................................11
SECTION 3.04 Interest on Cash on Hand....................................................................11
SECTION 3.05 Power to Settle Claims......................................................................12
SECTION 3.06 Power to Contract for Services; Transfer Agents and
Registrar...................................................................................12
SECTION 3.07 Payment of Liabilities of Trust.............................................................13
SECTION 3.08 Income and Principal........................................................................14
SECTION 3.09 Term of Contracts...........................................................................14
SECTION 3.10 Transactions With Entity Serving as the Trustee or the
Delaware Trustee............................................................................14
SECTION 3.11 No Security Required........................................................................15
SECTION 3.12 Divestiture of Units........................................................................15
SECTION 3.13 Filing of Registration Statements, Listing of Units.........................................16
SECTION 3.14 Reserve Report..............................................................................18
</TABLE>
<PAGE> 3
<TABLE>
<S> <C>
ARTICLE IV
TRUST UNITS AND BENEFICIAL INTEREST IN CERTIFICATES
SECTION 4.01 Creation and Distribution...................................................................18
SECTION 4.02 Rights of Unitholders; Limitation on Personal Liability of Unitholders......................18
SECTION 4.03 Execution of Certificates...................................................................19
SECTION 4.04 Registration and Transfer of Units; Lost and Destroyed Certificates.........................20
SECTION 4.05 Protection of Delaware Trustee and Trustee..................................................21
SECTION 4.06 Determination of Ownership..................................................................21
ARTICLE V
ACCOUNTING AND DISTRIBUTION; REPORTS
SECTION 5.01 Fiscal Year and Accounting Method...........................................................22
SECTION 5.02 Quarterly Distributions.....................................................................22
SECTION 5.03 Income Tax Reporting........................................................................23
SECTION 5.04 Reports to Unitholders and Others...........................................................23
SECTION 5.05 Information to be Supplied by Eastern States and Trustee....................................24
ARTICLE VI
LIABILITY OF DELAWARE TRUSTEE AND TRUSTEE AND METHOD OF
SUCCESSION
SECTION 6.01 Liability of Delaware Trustee and Trustee...................................................24
SECTION 6.02 Indemnification of Trustee and Delaware Trustee.............................................25
SECTION 6.03 Resignation of Delaware Trustee and Trustee.................................................27
SECTION 6.04 Removal of Delaware Trustee and Trustee.....................................................28
SECTION 6.05 Appointment of Successor Delaware Trustee or Trustee........................................28
SECTION 6.06 Laws of Other Jurisdictions.................................................................29
SECTION 6.07 Reliance on Experts.........................................................................30
SECTION 6.08 Failure of Action by Eastern States.........................................................30
SECTION 6.09 Force Majeure...............................................................................30
</TABLE>
ii
<PAGE> 4
<TABLE>
<S> <C>
ARTICLE VII
COMPENSATION OF THE TRUSTEE AND DELAWARE TRUSTEE
SECTION 7.01 Compensation of Trustee and Delaware Trustee................................................30
SECTION 7.02 Source of Funds.............................................................................31
SECTION 7.03 Ownership of Units by Eastern States, the Trustee and Delaware Trustee......................31
ARTICLE VIII
MEETINGS OF UNITHOLDERS
SECTION 8.01 Purpose of Meetings.........................................................................31
SECTION 8.02 Call and Notice of Meetings.................................................................31
SECTION 8.03 Method of Voting and Vote Required..........................................................32
SECTION 8.04 Conduct of Meetings.........................................................................32
SECTION 8.05 Unitholder Proposals........................................................................32
ARTICLE IX
DURATION, REVOCATION AND TERMINATION OF TRUST
SECTION 9.01 Revocation..................................................................................33
SECTION 9.02 Dissolution.................................................................................33
SECTION 9.03 Disposition and Distribution of Assets and Properties.......................................34
SECTION 9.04 Conditional Right of Repurchase.............................................................36
SECTION 9.05 Reorganization or Business Combination......................................................37
ARTICLE X
AMENDMENTS
SECTION 10.01 Prohibited Amendments.......................................................................38
SECTION 10.02 Permitted Amendments........................................................................39
</TABLE>
iii
<PAGE> 5
<TABLE>
<S> <C>
ARTICLE XI
ARBITRATION
ARTICLE XII
MISCELLANEOUS
SECTION 12.01 Inspection of Trustee'sBooks................................................................42
SECTION 12.02 Disability of a Unitholder..................................................................42
SECTION 12.03 Merger or Consolidation of Trustee or Delaware Trustee......................................42
SECTION 12.04 Change in Trust Name........................................................................42
SECTION 12.05 Filing of this Agreement....................................................................43
SECTION 12.06 Choice of Law...............................................................................43
SECTION 12.07 Severability................................................................................43
SECTION 12.08 Notices.....................................................................................43
SECTION 12.09 Counterparts................................................................................44
SECTION 12.10 Successors..................................................................................44
</TABLE>
iv
<PAGE> 6
TRUST AGREEMENT
OF
APPALACHIAN NATURAL GAS TRUST
This Amended and Restated Trust Agreement of Appalachian Natural Gas
Trust (the "Trust") is entered into effective as of the 1st day of September
1999, by and among Eastern States Oil & Gas, Inc., a Delaware corporation with
its principal office in Alexandria, Virginia ("Eastern States"), as sponsor, and
Bank One Delaware, Inc., a banking corporation organized under the laws of the
State of Delaware with its principal office in Wilmington, Delaware ("Bank One
Delaware"), and Bank One, Texas, N.A., a banking association organized under the
laws of the United States of America with its principal office in Fort Worth,
Texas (the "Bank"), as trustees.
R E C I T A L S:
WHEREAS, Eastern States is engaged in the development, production,
acquisition, marketing, gathering and transportation of natural gas and oil; and
WHEREAS, Eastern States has determined to convey to the Trust the
Royalty Interests (hereinafter defined) pursuant to the Conveyances (hereinafter
defined) in consideration for the issuance by the Trust of 10,500,000 Units
(hereinafter defined); and
WHEREAS, Eastern States and Bank One Delaware have previously formed
the Trust pursuant to the Organizational Trust Agreement (hereinafter defined)
in accordance with the provisions of the Business Act (hereinafter defined) and,
in connection therewith, Eastern States has previously delivered to the Bank, on
behalf of the trust, good and valuable consideration, which the Bank has
accepted, to have and to hold, in trust, such property and all other properties
that may hereafter be received, for purposes and subject to the terms and
conditions hereinafter provided;
NOW, THEREFORE, Eastern States, Bank One Delaware and the Bank hereby
amend and restate the Organizational Trust Agreement of Appalachian Basin
Royalty Trust in its entirety.
ARTICLE I
DEFINITIONS
SECTION 1.01 Definitions.
As used herein, the following terms have the meanings indicated:
"Advisor" shall have the meaning assigned to such term in Section 9.03
of this Agreement.
"Affiliate" of a Person means another Person controlled by, controlling
or under common control with such Person. As used herein, "control" (including
the terms "controlling", "controlled by" and "under common control with") means
the possession, directly or indirectly, of the power to
<PAGE> 7
direct or cause the direction of the management and policies of a Person,
whether through the ownership of voting securities, by contract or otherwise.
"Agreement" means this instrument, as originally executed, or, if
amended or supplemented, as so amended or supplemented.
"Bank" means Bank One Texas, N.A., its successors and assigns.
"Bank One Delaware" means Bank One Delaware, Inc., its successors and
assigns.
"Beneficial Interest" means the aggregate undivided beneficial interest
of all Unitholders in the Trust Estate, including, without limitation, the right
to receive distributions of proceeds from the conversion of the Royalty
Interests to cash, and the right to receive distributions of cash resulting from
such conversion of the Royalty Interests, which beneficial interest is expressed
in Units, but such beneficial interest does not include any ownership interest,
in or to the Royalty Interests, or any part thereof, or in or to any other asset
of the Trust Estate to the extent that an interest in such asset would cause the
interest of a Unitholder to be treated (other than for Federal income tax
purposes) as other than an intangible personal property interest.
"Best Efforts" means a Person's best efforts in accordance with
reasonable commercial practice and without the incurrence of unreasonable
expense.
"Business Act" means the Delaware Business Trust Act, Title 12, Chapter
38 of the Delaware Code, Sections 3801 et seq., as amended from time to time
during the term of this Agreement.
"Business Day" means any day that is not a Saturday, Sunday, a holiday
determined by the NYSE as "affecting 'ex' dates" or any other day on which
national banking institutions in Fort Worth, Texas are closed as authorized or
required by law.
"Certificate" means a certificate issued by the Trustee pursuant to
Article IV hereof evidencing the ownership of one or more Units.
"Closing" means the closing of the initial public offering contemplated
by the Securities Act Registration Statement.
"Code" means the Internal Revenue Code of 1986, a amended.
"Commission" means the Securities and Exchange Commission.
"Confirmation" means an entry made on the ownership ledger maintained
by the Trustee pursuant to Section 3.12 hereof.
2
<PAGE> 8
"Conveyances" means the Net Overriding Royalty Conveyances effective as
of September 1, 1999 between Eastern States and the Trust, pursuant to which the
Royalty Interests are to be conveyed to the Trust.
"Delaware Trustee" means the Entity serving as a trustee hereunder
having its principal place of business in Delaware, in its fiduciary capacity.
Further, any benefit, indemnity, release or protection granted to the Delaware
Trustee herein shall extend to and shall be fully applicable and effective with
regard to any Entity serving as the Delaware Trustee, including, without
limitation, Bank One Delaware.
"Distribution Date" means the date of a distribution, which shall be on
or before the 25th day of the third calendar month following the end of a
calendar quarter.
"Effective Time" means 12:01 a.m. on September 1, 1999.
"Entity" means a corporation, partnership, limited liability company,
trust, estate or other organization.
"Environmental Laws" means all laws relating to pollution or protection
of the environment, including laws relating to emissions, discharges, releases
or threatened releases, treatment, storage or disposal of pollutants,
contaminants, hazardous substances or industrial or hazardous wastes into the
environment (including ambient air, surface water, groundwater, land surface or
subsurface strata), and also including laws relating to the protection,
preservation, or enhancement of endangered or threatened species, historic and
archaeological resources, or wetlands and tidelands, as well as codes, decrees,
injunctions, judgments, orders, rules or regulations issued, entered,
promulgated or approved thereunder pursuant to the requirements of applicable
administrative procedures acts and agency procedural rules.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Exchange Act Registration Statement" means the registration statement
pursuant to which the Units may be registered under Section 12 of the Exchange
Act.
"Indemnified Party" and "Indemnified Parties" shall have the meaning
assigned to such terms in Section 6.02(d) hereof.
"Indemnifying Party" shall have the meaning assigned to such term in
Section 6.02(d) hereof.
"Ineligible Holder" shall have the meaning assigned to such term in
Section 3.12 hereof.
"Notice" shall have the meaning assigned to such term in Section 3.12
of this Agreement.
"NYSE" means the New York Stock Exchange, Inc.
3
<PAGE> 9
"Organizational Trust Agreement" means the Trust Agreement of
Appalachian Basin Royalty Trust, dated as of August 1, 1999, as amended on
October 1999 in order to change the name of the Trust to Appalachian Natural Gas
Trust, by and among Eastern States, as sponsor, Bank One Delaware, as trustee,
and Kerry W. Eckstein, as trustee.
"Person" means an individual or Entity.
"Quarterly Distribution Amount" means for each Quarterly Period an
amount determined by the Trustee pursuant to Section 5.02 hereof to be equal to
the excess, if any, of (a) the cash received by the Trust attributable to
production from the Royalty Interests during such Quarterly Period provided that
such cash attributable to such production is received by the Trust on or before
the 22nd calendar day of the third month following the end of the Quarterly
Period, plus other cash received by the Trust during such Quarterly Period, plus
any decrease during such Quarterly Period in any cash reserve theretofore
established by the Trustee for the payment of liabilities of the Trust, over (b)
the liabilities of the Trust paid during such Quarterly Period, plus the amount
of any cash used during such Quarterly Period by the Trustee to establish or
increase a cash reserve established for the payment of any liabilities of the
Trust. Without limiting the foregoing, the liabilities of the Trust to be paid
during the first Quarterly Period shall include liabilities incurred prior to
the Effective Time that relate to the formation of the Trust or for which the
Trust, the Trustee or the Delaware Trust is otherwise responsible for payment.
If the Quarterly Distribution Amount determined in accordance with the preceding
sentence shall for any Quarterly Period be a negative amount, then the Quarterly
Distribution Amount shall be zero, and such negative amount shall reduce the
next Quarterly Distribution Amount. Notwithstanding the foregoing, the Quarterly
Distribution Amount for any Quarterly Period shall not include any amount that
would have been required to be reported to any securities exchange on which the
Units are listed in connection with the establishment of an "ex" date in order
to be distributed to Unitholders who were such on the Quarterly Record Date for
such Quarterly Period but was not so reported unless the securities exchange
agrees to such amount being a part of that Quarterly Period's Quarterly
Distribution Amount or the Trustee receives an opinion of counsel, in a form
reasonably satisfactory to the Trustee, stating that none of the Trust, the
Trustee, the Delaware Trustee, or any owner of Units will be adversely affected
by such inclusion. An amount that pursuant to the preceding sentence is not
included in the Quarterly Distribution Amount for that Quarterly Period shall be
included in the Quarterly Distribution Amount for the next Quarterly Period
(unless it is reserved pursuant to Section 3.07 hereof).
"Quarterly Period" means, for the initial period, the period commencing
on the Effective Time and continuing through and including September 30, 1999,
and for succeeding periods, each of the three calendar month periods ending on
the last day of March, June, September and December of each year.
"Quarterly Record Date" means, for each Quarterly Period, the close of
business on the fifteenth day of the third calendar month following the end of
such Quarterly Period (or if not a Business Day, on the next Business Day
thereafter) unless the Trustee determines that another date
4
<PAGE> 10
is required to comply with applicable law or the rules of any securities
exchange on which the Units may be listed for trading, in which event "Quarterly
Record Date" means such other date.
"Reserve Report" means a report of estimated proved reserves
attributable to the Royalty Interests and the present value thereof prepared on
the basis required by the Commission for inclusion in financial statements filed
with the Commission.
"Record Date Unitholders" shall have the meaning assigned to such term
in Section 8.02 of this Agreement.
"Remaining Royalty Interests" shall have the meaning set forth in
Section 9.03 of the Agreement.
"Royalty Interests" shall have the meaning set forth in Article I of
each of the Conveyances.
"Sales Proceeds Amount" means any cash paid to the Trust in
consideration for Royalty Interests pursuant to Sections 3.02(a), 3.02(b) or
9.03 hereof.
"Securities Act" means the Securities Act of 1933, as amended.
"Securities Act Registration Statement" means the Registration
Statement on Form S-1 (Registration No. 333-85955) as it has been or as it may
be amended or supplemented from time to time, filed by Eastern States with the
Commission under the Securities Act to register the offering and sale of the
Units.
"Standardized Measure" means the present value of estimated future net
revenues computed by discounting estimated future net revenues at a rate of 10%
annually.
"Termination Date" means the date on which the Trust is terminated in
accordance with Section 9.02 hereof.
"Termination Present Value" means the discounted net present value of
estimated future net revenues from proved reserves attributable to the Royalty
Interests computed in accordance with the third sentence of Section 3.14 hereof.
"Transferee" means, as to any Unitholder or former Unitholder, any
Person succeeding to the interest of such Unitholder or former Unitholder in one
or more Units, whether as purchaser, donee, legatee or otherwise.
"Trust" means the trust created by and administered under the terms of
this Agreement. When used in reference to a payment, means a payment chargeable
against the Trust Estate, when used in reference to any type of actual or
asserted liability, means an actual or asserted liability as to which an Entity
serving as a trustee hereunder is liable and is entitled to indemnification
under
5
<PAGE> 11
Section 6.02 of this Agreement, or which is otherwise satisfiable out of the
Trust Estate, when used in reference to receipts, means receipts that augment
the Trust Estate, and when used in reference to income and deductions, means
receipts and payments described above that constitute income and deductions for
accounting or tax purposes as applicable.
"Trust Estate" means the assets held under this Agreement.
"Trustee" means the Entity serving as a trustee (other than the
Delaware Trustee) under this Agreement, in its fiduciary capacity. Further, any
benefit, indemnity, release or protection granted to Trustee hereunder shall
extend to and be fully applicable and effective with regard to any Entity
serving as Trustee, including, without limitation, the Bank.
"Trustee Conveyance" means a conveyance executed by the Trustee and
Delaware Trustee pursuant to Section 3.02 of this Agreement covering that
portion of the Royalty Interests to be conveyed pursuant to said Section and in
such form as the Trustee is advised is sufficient to transfer the right, title
and interest of the Trust therein and to provide for payment to the Trustee of
all revenues attributable thereto through the effective date of such Trustee
Conveyance.
"Underlying Properties" means, collectively, the Existing Wells and the
Subject Interests, as such terms are defined in Article I of each of the
Conveyances.
"Underwriting Agreement" shall have the meaning assigned to such term
in Section 2.03 of this Agreement.
"Unit" or "Units" means an undivided fractional interest in the
Beneficial Interest, determined as hereinafter provided.
"Unitholder" means the owner of one or more Units as reflected on the
ownership ledger of the Trustee maintained for such purpose.
ARTICLE II
NAME AND PURPOSE OF THE TRUST; DECLARATION OF TRUST
SECTION 2.01 Name.
The Trust shall be known as the Appalachian Natural Gas Trust, and the
Trustee may transact the Trust's affairs in that name. The Trust shall
constitute a Delaware business trust in accordance with the Business Act. The
organization and operation of the Trust shall be in accordance with this
Agreement, which shall constitute the governing instrument of the Trust within
the meaning of Section 3801(f) of the Business Act. Eastern States has caused a
Certificate of Trust, duly executed by the Trustee and the Delaware Trustee in
accordance with Section 3811 of the Business Act, to be filed on behalf of the
Trust in the office of the Secretary of State of Delaware in accordance with
6
<PAGE> 12
Section 3810 of the Business Act. If either the Delaware Trustee or the Trustee
becomes aware that any statement contained or matter described in the
Certificate of Trust has changed making it false in any material respect, it
will notify the other trustee and the Trustee shall promptly file or cause to be
filed in the office of the Secretary of State of Delaware an amendment of same,
duly executed in accordance with Section 3811 of the Business Act, in order to
effect such change thereto as the Trustee determines in its sole discretion to
be necessary or appropriate, such filing to be in accordance with Section
3810(b) of the Business Act. Upon the termination of the Trust pursuant to
Section 9.02 hereof and the complete distribution of all of the Trust Estate,
the Trustee shall file or cause to be filed a certificate of cancellation, duly
executed in accordance with Section 3811 of the Business Act.
SECTION 2.02 Purposes.
The purposes of the Trust are, and the Trust shall have the power and
authority and is authorized:
(a) to protect and conserve, for the benefit of the Unitholders, the
Trust Estate;
(b) to receive and hold the Royalty Interests and other assets of the
Trust Estate;
(c) to convert the Royalty Interests to cash either by (1) retaining
the Royalty Interests and collecting the proceeds of production payable with
respect to the Royalty Interests until production has ceased or the Royalty
Interests have been sold or transferred or (2) selling or otherwise disposing of
all or a portion of the Royalty Interests in accordance with and subject to the
terms of this Agreement;
(d) to pay, or provide for the payment of, any liabilities incurred
in carrying out the purposes of the Trust, and thereafter to distribute the
remaining amounts of cash received by the Trust to the Unitholders pro rata
based on the number of Units owned;
(e) (i) to prepare and file with the Commission and to execute, in
the case of the Securities Act Registration Statement and the Exchange Act
Registration on behalf of the Trust (A) the Securities Act Registration
Statement, including all pre-effective and post-effective amendments thereto,
relating to registration under the Securities Act of the trust securities of the
Trust, (B) any preliminary prospectus or prospectus or supplement thereto
relating to the trust securities of the Trust required to be filed pursuant to
the Securities Act, and (C) the Exchange Act Registration Statement, including
all pre-effective and post-effective amendments thereto, relating to the
registration of the trust securities of the Trust under the Exchange Act; (ii)
to file to list the trust securities of the Trust with the NYSE, or other
exchange, or the National Association of Securities Dealers (the "NASD") and
execute on behalf of the Trust a listing application and all other applications,
statements, certificates, agreements and other instruments as shall be necessary
or desirable to cause the trust securities to be listed on the NYSE or such
other exchange, or the NASD's Nasdaq National Market; (iii) to file and execute
on behalf of the Trust, such applications,
7
<PAGE> 13
reports, surety bonds, irrevocable consents, appointments of attorney for
service of process and other papers and documents that shall be necessary or
desirable to register the trust securities of the Trust under the securities or
"blue sky" laws of such jurisdictions as Eastern States, on behalf of the Trust
may deem necessary or desirable; (iv) to execute and deliver letters or
documents to, or instruments for filing with, a depository relating to the trust
securities of the Trust; (v) to execute, deliver and perform on behalf of the
Trust, one or more Conveyances; and to execute, deliver and perform on behalf of
the Trust the Underwriting Agreement;
(f) to enter into and perform its obligations under the
Conveyances, the Underwriting Agreement and such other agreements that the Trust
is a party to from time to time;
(g) subject to Section 3.03 of this Agreement, to engage in
such other activities as are necessary or convenient for the attainment of any
of the foregoing or are incident thereto and which may be engaged in or carried
on by a business trust under the Business Act.
SECTION 2.03 Transfer of Trust Property to the Trust; Closing Matters.
At or before (and subject to the occurrence of) the Closing, Eastern
States shall grant, bargain, sell, convey and assign the Royalty Interests to
the Trust for the uses and purposes provided herein, pursuant to the Conveyances
in consideration for 10,500,000 Units to be issued by the Trust to Eastern
States, which Units shall collectively represent the entire Beneficial Interest
in accordance with Section 4.01 of this Agreement. The Units to be issued by the
Trust to Eastern States in accordance with the preceding sentence shall be
evidenced by one or more Certificates (which may be temporary Certificates)
issued pursuant to Section 4.03 of this Agreement in such denominations and
otherwise in accordance with written instructions furnished to the Trustee. Upon
receipt of written transfer instructions from Eastern States, the Trustee shall
prepare Certificates (which may be temporary Certificates) in proper form duly
executed, countersigned and authenticated in accordance with Section 4.03 of
this Agreement in such names and in such denominations as Eastern States may
request in writing not less than two full Business Days before the Closing. For
the purpose of expediting the checking and packaging of the Certificates so
prepared by the Trustee pursuant to the preceding sentence, the Trustee shall
make such Certificates available for inspection by the representatives of the
several underwriters named in the Securities Act Registration Statement. The
Trustee shall deliver such Certificates to such location and at such time as is
stated in the written transfer instructions from Eastern States and shall
release such Certificates (a) upon the receipt from Eastern States of one or
more Certificates, duly endorsed for transfer, that evidence a number of Units
equal to or not less than the number of Units evidenced by the Certificates to
be so released and (b) in accordance with the instructions of Eastern States. At
the Closing, the Trustee and the Delaware Trustee shall receive the following
documents dated as of the date of the Closing: (i) opinions of Andrews & Kurth
L.L.P. and Richards, Layton & Finger, PA addressed to the Trustee and the
Delaware Trustee substantially in the forms of the respective opinions to be
delivered by such counsel at the Closing pursuant to the underwriting agreement
referred to in the Securities Act Registration Statement (the "Underwriting
Agreement"), (ii) opinions of Goodwin & Goodwin, LLP and Vorys, Sater, Seymour
and Pease L.L.P. addressed to the Trustee and the Delaware Trustee
8
<PAGE> 14
substantially in the forms of the respective opinions to be delivered by such
counsel at the Closing pursuant to the Underwriting Agreement, (iii) a
certificate of Eastern States signed by its President or a Senior Vice President
certifying that the representations and warranties of Eastern States contained
in the Underwriting Agreement are true and correct as of the date of the Closing
and (iv) such other documents or certificates as the Trustee or the Delaware
Trustee may reasonably request; provided, that the opinions referred to in
clause (ii) and the representations and warranties referred to in clause (iii)
are not substantially different in effect, with respect to the interests of the
Trustee and the Delaware Trustee, from the opinions described and the
representations and warranties set forth in the form of Underwriting Agreement
filed as Exhibit 1.1 to Amendment No. 1 to the Securities Act Registration
Statement.
SECTION 2.04 Nature of the Trust.
Each of the Trustee and the Delaware Trustee declares that it shall
hold the Trust Estate in trust for the benefit of the Unitholders, upon the
terms and conditions set forth in this Agreement. It is the intention of Eastern
States to create a grantor trust for federal income tax purposes of which the
Unitholders are treated, for federal income tax purposes, as the owners of trust
income and corpus. As set forth above and amplified herein, the Trust is
intended to be a passive entity limited to the receipt of revenues attributable
to the Royalty Interests and the distribution of such revenues, after payment of
or provision for Trust expenses and liabilities, to the Unitholders. It is not
the intention of the parties hereto to create, and nothing in this Agreement
shall be construed as creating, for tax purposes, a partnership, joint venture,
joint stock company or similar business association, between or among
Unitholders, present or future, or between or among Unitholders, or any of them,
the Trustee, the Delaware Trustee or Eastern States.
SECTION 2.05 Principal Office and Delaware Trustee.
Unless and until changed by the Trustee, the address of the principal
office of the Trust is 500 Throckmorton, Suite 801, Fort Worth, Texas 76102.
Unless and until changed by the Delaware Trustee, the principal place of
business of the Delaware Trustee is Three Christina Center, 201 North Walnut
Street, Wilmington, Delaware 19801. The Trust may maintain offices at such other
place or places within or without the State of Delaware as the Trustee deems
advisable.
ARTICLE III
ADMINISTRATION OF THE TRUST AND POWERS OF THE
TRUSTEE AND THE DELAWARE TRUSTEE
SECTION 3.01 General Authority.
(a) The Trustee accepts the trust created hereby and agrees to
perform its duties with respect to such trust upon the terms of this Agreement.
Subject to the limitations set forth in this Agreement, the Trustee, acting
alone without the approval or consent of or notice to the
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Delaware Trustee or any Unitholder, is authorized to take such action as in its
judgment is necessary, desirable or advisable to best achieve the purposes of
the Trust, including the authority to enter into the Conveyances, to agree to
amendments, ratifications, consents, waivers or settlements of the terms of any
of the Conveyances or to settle disputes with respect thereto, so long as (a)
such amendments, ratifications, consents, waivers or settlements do not alter
the nature of the Royalty Interests as a right to receive a share of the net
proceeds from production from the Underlying Properties in accordance with the
Conveyances which, with respect to the Trust, are free of any operating rights,
expenses or obligations and (b) such amendments, ratifications, consents,
waivers or settlements do not result in treatment of the Trust as an association
taxable as a corporation for federal income tax purposes. The Trustee shall not
dispose of any part of the Trust Estate except as provided in Sections 3.02,
3.07, 5.02 and 9.03 of this Agreement. Except as provided in this Section 3.01,
the Trustee shall not agree to any amendment or waiver of any provision of, give
any consent or release with respect to, or agree to the termination of the
Conveyances without the requisite consent of Unitholders, pursuant to Article
VIII of this Agreement.
(b) The Delaware Trustee accepts the trust created hereby and
agrees to perform its duties hereunder with respect to the trust upon the terms
of this Agreement. The Delaware Trustee is authorized to take only such actions,
and shall be required to perform only such duties and obligations, with respect
to the Trust as are specifically set forth in this Agreement, and no implied
duties or obligations shall be read into this Agreement against the Delaware
Trustee. The Delaware Trustee shall not otherwise manage or take part in the
business or affairs of the Trust in any manner. Notwithstanding any other
provision of this Agreement, unless specifically authorized in writing by the
Trustee and consented to by the Delaware Trustee, the Delaware Trustee shall not
participate in any decisions or possess any authority with respect to the
administration of the Trust, the investment of the Trust's property or the
payment of distributions of income or principal to the Unitholders. The Delaware
Trustee shall have the power and authority to and, as directed by the Trustee or
counsel to the Trust, shall execute, deliver, acknowledge and file all necessary
documents and to maintain all necessary records of the Trust as required by the
Business Act, and the Delaware Trustee shall provide prompt written notice to
the Trustee of its performance of any of the foregoing acts.
SECTION 3.02 Limited Power of Disposition.
(a) The Trustee may sell, at any time and from time to time,
(i) Royalty Interests of which the aggregate Standardized Measure as of the end
of the most recently completed calendar year does not exceed $30 million and
holders of Units representing a majority of Units present or represented at a
meeting held in accordance with Article VIII approve such sale and (ii) Royalty
Interests of which the aggregate Standardized Measure exceeds $30 million and
holders of Units representing at least 66 2/3% of the outstanding Units present
or represented at a meeting held in accordance with Article VIII approve such
sale. This Section 3.02(a) shall not be construed to require approval of the
Unitholders for any sale or other disposition of all or any part of the Royalty
Interests pursuant to Sections 3.02(b), 3.05, 3.09. or 9.03. The Trustee is
authorized to retain any of the Royalty Interests in the form in which such
property was transferred to the Trustee, without regard to any requirement to
diversify investments or other requirements.
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(b) Eastern States may notify the Trustee, at any time and
from time to time, that it desires to sell for cash any of the Underlying
Properties to any Person not an Affiliate of Eastern States free of and
unburdened by the Royalty Interests if the net cash sales price payable to the
Trust for the Royalty Interests to be so sold pursuant to this Section 3.02(b)
does not exceed $3 million in any calendar year or $20 million on an aggregate
basis for the life of the Trust. Upon receipt of such notice the Trustee shall
be required to join in such sale and execute and deliver a partial release,
assignment or such other instrument as Eastern States may reasonably request to
evidence that such Underlying Properties are being sold free and unburdened by
the Royalty Interests. The net cash proceeds payable to the Trust from any sale
pursuant to this Section 3.02(b) shall be allocated to the Trust based on such
methodology as Eastern States determines to be fair and reasonable under the
circumstances taking into account, among other factors, the Standardized Measure
attributable to the Royalty Interests so sold in comparison to the aggregate
Standardized Measure of the Royalty Interests and the Underlying Properties so
sold.
SECTION 3.03 No Power to Engage in Business or Make Investments.
Neither the Trustee nor the Delaware Trustee shall cause the Trust to
acquire any asset other than the Royalty Interests and proceeds therefrom and
other amounts paid to the Trust as set forth herein, or engage in any business
or investment activity of any kind whatsoever, except for the activities
permitted herein. Neither the Trustee nor the Delaware Trustee shall have any
responsibility or authority relating to the operations of the Underlying
Properties or the marketing of any production therefrom. Neither the Trustee nor
the Delaware Trustee shall accept contributions to the Trust other than the
Royalty Interests and the initial cash deposit.
SECTION 3.04 Interest on Cash on Hand.
Cash being held by the Trustee as a reserve for the distribution of a
Quarterly Distribution Amount or for the payment of any liabilities of the
Trust, other than current routine administrative costs shall be placed by the
Trustee with one or more banks or financial institutions (which, to the extent
to which authorized pursuant to the Business Act and other applicable law, may
be or may include any bank serving as the Trustee or the Delaware Trustee) and
invested in (i) obligations issued by (or unconditionally guaranteed by) the
United States of America or any agency or instrumentality thereof (provided such
agency or instrumentality obligations are guaranteed by the full faith and
credit of the United States of America), (ii) repurchase agreements secured by
obligations qualifying under (i) above, (iii) money market mutual funds
(including One Group U.S. Treasury Securities Money Market Fund and other such
funds of the Trustee and its affiliates) registered under the Investment Company
Act of 1940, as amended, that have been rated AAAmg or AAAm by S&P and Aaa by
Moody's; provided that the portfolio of such money market mutual fund is limited
to obligations described in (i) above and to agreements to repurchase such
obligations, or (iv) a certificate of deposit of any bank having capital,
surplus and undivided profits in excess of $100,000,000 which, in the case of
(ii), (iii) and (iv) above, matures prior to the date on which such Quarterly
Distribution Amount is to be distributed or any such liability is to be paid.
Any government obligation, repurchase agreement or certificate of deposit held
by the Trustee shall
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be held until maturity. The interest rate on reserves placed with any bank
serving as the Trustee or the Delaware Trustee shall be the interest rate that
such bank pays in the normal course of business on amounts placed with it,
taking into account the amount involved, the period held and other relevant
factors.
SECTION 3.05 Power to Settle Claims.
Subject to the limitations specified in Article XI, the Trustee is
authorized to prosecute or defend, and to settle by arbitration or otherwise,
any claim of or against the Trustee, the Trust or the Trust Estate, to waive or
release rights of any kind and to pay or satisfy any debt, tax or claim upon any
evidence by it deemed sufficient, without the joinder or consent of any
Unitholder. Such authority shall include, but not be limited to, the authority
to dispose of or relinquish title to any of the Royalty Interests that are the
subject of such a dispute upon receipt of such evidence. The Trustee agrees to
respond definitively to, and within a commercially reasonable time period
following its receipt of, any written request by Eastern States relating to any
such claim and complying with the last sentence of this Section 3.05, and the
failure of the Trustee so to respond definitively and timely shall conclusively
estop the Trustee from thereafter claiming a right that is inconsistent with the
stated intent as set forth in the notice and materially detrimental to Eastern
States or its Affiliates with respect to such requested matter. Any request made
by Eastern States intended to be governed by this Section 3.05 shall
specifically reference this Section.
SECTION 3.06 Power to Contract for Services; Transfer Agents and Registrar.
In the administration of the Trust, the Trustee is empowered to employ
oil and natural gas consultants, independent reservoir engineers, accountants
(who may be the same engineering or accounting firm who are engaged as outside
engineers or auditors for Eastern States, as the case may be), attorneys (who
may be counsel to Eastern States unless Eastern States otherwise notifies the
Trustee in writing) and other professional and expert persons, to employ or
contract for clerical and other administrative assistance (including assistance
from Eastern States and any of its Affiliates), to delegate to agents and
employees any matter, whether ministerial or discretionary, and to act through
such agents and employees, and to make payments of all fees for services or
expenses in any manner thus incurred out of the Trust Estate. Without limiting
the generality of the foregoing, the Trustee is specifically empowered to engage
one or more securities brokers, investment banking firms, or agents or other
experts experienced in the sale of oil and natural gas properties to assist in
the sale of the Royalty Interests pursuant to Sections 3.02(a) and 9.03 hereof
and, from time to time in its discretion, to appoint as a transfer agent and/or
registrar for the Units any Entity qualified to so serve as transfer agent
and/or registrar, delegating to such Entity the rights, powers and duties
incident thereto, whether ministerial or discretionary, and to remove such
appointee and appoint another or itself to perform such functions; provided that
in so appointing, delegating and removing, the Trustee shall be guided by the
goals of obtaining proper performance of such functions and reasonably
minimizing the costs incident thereto. The Trustee shall, on behalf of the
Trust, retain [EquiServe] as the initial transfer agent and registrar for the
Units.
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In addition, the Trustee is specifically empowered to engage one or
more persons to furnish to the Trust accounting, bookkeeping and other
administrative services and reports (collectively, "Administrative Services")
necessary (a) to determine the Net Proceeds and any other amounts payable to the
Trust pursuant to the Conveyances, (b) to provide to the Trust information
required for the Trust to provide to the Unitholders financial statements and
other information with respect to Eastern States' interests in the Underlying
Properties in the manner described in the prospectus constituting a part of the
Securities Act Registration Statement under the caption "Available Information,"
and (c) to provide all information relating to the Royalty Interests and the
Underlying Properties as shall be necessary (i) to permit the Trustee to comply,
with respect to the Trust, with the reporting obligations of the Trust pursuant
to the Exchange Act (including, without limitation, such reporting obligations
with respect to required financial statements and supplementary financial
information), the requirements of any securities exchange or quotation system on
which the Units are listed or admitted for trading and the Trust Agreement, (ii)
to sell the Royalty Interests in accordance with the Trust Agreement and (iii)
for any other reasonable purpose of the Trust; provided, however, that
Administrative Services shall not include (A) furnishing information other than
with respect to the Royalty Interests or the Underlying Properties, (B)
preparing any filings on behalf of the Trust, (C) performing any services by or
at the direction of the Trustees on behalf of the Trust pursuant to the Trust
Agreement other than as contemplated herein or (D) the furnishing of any
information, data, documents or materials precluded by Section 3.14 and the
penultimate sentence of Section 5.05 of the Trust Agreement. The Trustee
initially engages Eastern States to provide such Administrative Services,
provided that none of Eastern States, its officers, directors, agents, employees
and Affiliates shall be liable to the Trust, the Trustee or Unitholders for
claims, demands, damages, losses, liabilities, costs or expenses (including,
without limitation, reasonable attorneys' fees and other costs and expenses
incident to any suit, proceeding or investigation of any claim) arising out of
the rendering of the Administrative Services by Eastern States hereunder except
that Eastern States shall be liable for gross negligence or willful misconduct
in the rendering of the Administrative Services.
SECTION 3.07 Payment of Liabilities of Trust.
Except as otherwise provided in this Agreement, the Trustee shall, to
the extent that funds of the Trust are available therefor (which shall not
include funds previously set aside for payment of a Quarterly Distribution
Amount), make payment or reimbursement of all liabilities of the Trust,
including, but without limiting the generality of the foregoing, all expenses,
taxes, liabilities incurred of all kinds, compensation to it for its services
hereunder, as provided for in Article VII, and compensation to such parties as
may be employed as provided for in Section 3.06 hereof. With respect to any
liability that is contingent or uncertain in amount or that otherwise is not
currently due and payable, the Trustee may, but is not obligated to, establish a
cash reserve for the payment of such liability. The Trustee shall not pay any
liability of the Trust with funds set aside pursuant to Section 5.02 of this
Agreement for the payment of a Quarterly Distribution Amount. If at any time the
cash on hand and to be received by the Trustee and available to pay liabilities
is not, or will not be, in the judgment of the Trustee, sufficient to pay
liabilities of the Trust as they become due, the Trustee is authorized to borrow
the funds required to pay such liabilities. In the event of such a borrowing, no
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further distributions shall be made to Unitholders (except in respect of a
previously determined Quarterly Distribution Amount) until the indebtedness
created by such borrowings has been paid in full. Such funds may be borrowed
from any Person, including, without limitation, the Bank while serving as
Trustee or any other Entity serving as a fiduciary hereunder, on a secured or
unsecured basis, provided that neither the Bank nor any other Entity shall be
required to make any such loan. To secure payment of such indebtedness
(including any indebtedness to the Bank or any other Entity serving as a
fiduciary hereunder), the Trustee is authorized to (i) mortgage, pledge, grant
security interests in or otherwise encumber the Trust Estate, or any portion
thereof, including the Royalty Interests, (ii) carve out and convey production
payments from the Royalty Interests, (iii) include any and all terms, powers,
remedies, covenants and provisions deemed necessary or advisable in the
Trustee's discretion, including, without limitation, confession of judgment and
the power of sale with or without judicial proceedings and (iv) provide for the
exercise of those and other remedies available to a secured lender in the event
of a default on such loan. If such funds are loaned to the Trust by the Bank or
any other Entity while the Bank or such other Entity is serving as a fiduciary
hereunder, the terms of such indebtedness and security interest shall be similar
to the terms which the Bank or such other Entity would grant to a similarly
situated commercial customer with whom it did not have, directly or indirectly,
a fiduciary relationship, and the Bank or such other Entity shall be entitled to
enforce its rights with respect to any such indebtedness and security interest
as if it were not, directly or indirectly, and had never been, directly or
indirectly, Trustee or a fiduciary hereunder.
SECTION 3.08 Income and Principal.
The Trustee shall not be required to keep separate accounts or records
for income and principal or maintain any reserve for depletion of the Royalty
Interests. However, if the Trustee does keep such separate accounts or records,
then the Trustee is authorized to treat all or any part of the receipts from the
Royalty Interests as income or principal, without having to maintain any reserve
therefor, and in general to determine all questions as between income and
principal and to credit or charge to income or principal or to apportion between
them any receipt or gain and any charge, disbursement or loss as is deemed
advisable under the circumstances of each case.
SECTION 3.09 Term of Contracts.
In exercising the rights and powers granted hereunder, the Trustee is
authorized to make the term of any transaction or contract or other instrument
extend beyond the term of the Trust.
SECTION 3.10 Transactions With Entity Serving as the Trustee or the Delaware
Trustee.
To the extent such conduct may be authorized under applicable law and
except as otherwise provided herein, each of the Trustee and the Delaware
Trustee is authorized in exercising its powers under this Agreement to make
contracts and have dealings with itself, directly and indirectly, in any other
fiduciary or individual capacity.
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SECTION 3.11 No Security Required.
No Entity serving as a trustee hereunder shall be required to furnish
any bond or security of any kind.
SECTION 3.12 Divestiture of Units.
If at any time (i) the Trust, the Trustee or the Delaware Trustee is
named a party in any judicial or administrative proceeding which seeks the
cancellation or forfeiture of any property in which the Trust has an interest or
asserting the invalidity of or otherwise challenging the Royalty Interests or
any portion thereof or (ii) the Trustee is notified by Eastern States or an
Affiliate of Eastern States in writing of any such proceeding to which Eastern
States or such Affiliate is made a party relating to the Underlying Properties,
in either case because of the nationality, citizenship or any other status, of
any one or more Unitholders, the following procedures shall be applicable:
(a) The Trustee shall promptly give written notice ("Notice")
to each Unitholder ("Ineligible Holder") whose nationality, citizenship or other
status is an issue in the proceeding as to the existence of such controversy.
The Notice shall contain a reasonable summary of such controversy, shall include
and shall constitute a demand to each Ineligible Holder that he dispose of his
Units to a Person which would not be an Ineligible Holder within 30 days after
the date of the Notice and shall advise such Ineligible Holder of the
consequences set forth in paragraphs (b) and (c) of this Section 3.12 if such
Ineligible Holder fails to dispose of his Units.
(b) If any Ineligible Holder fails to dispose of his Units
prior to the 90th day after the expiration of the 30-day period specified in the
Notice, the Trustee shall cancel all outstanding Certificates issued in the name
of such Ineligible Holder, effect a Confirmation reflecting the transfer of
Units evidenced by such cancelled Certificates to the Trust and issue a
Certificate in the name of the Trust evidencing such Units. Such Units shall be
held as treasury interests by the Trust and shall be deemed to be redeemed or
cancelled. Upon such issuance, the Trustee shall use Best Efforts to promptly
sell, to the extent permitted by law, such Units on a securities exchange or
other securities market where such Units are listed or otherwise traded. If the
Units are not at such time actively traded on a securities exchange or other
securities market, the Trustee shall use Best Efforts to effect a private sale
in any manner permitted by law. The Ineligible Holder shall be given notice of
any such cancellation and subsequent transfer at his address as shown on the
records of the Trustee in accordance with Section 11.08 hereof accompanied by a
request that such Ineligible Holder surrender to the Trustee the cancelled
Certificates. Upon receipt by the Trustee of the cancelled Certificates, the
Trustee shall pay the proceeds of any such sale (net of sales expenses) to the
Ineligible Holder. If the cancelled Certificates are not surrendered, the tender
is refused by the Ineligible Holder or if the Ineligible Holder cannot be
located after reasonable efforts, the above cash purchase price shall be held by
the Trustee in a non-interest bearing escrow account (which account shall not
constitute a part of the Trust Estate) for the benefit of such Ineligible
Holder, until proper claim for same has been made by such Ineligible Holder,
subject to applicable laws concerning unclaimed property.
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Any Certificate previously evidencing Units transferred to the Trustee pursuant
to this Section 3.12 shall cease to represent any Units.
(c) If any Ineligible Holder fails to dispose of his Units
within 30 days after the date of the Notice, cash distributions in respect of
Units for Quarterly Record Dates following the expiration of such 30-day period
shall be suspended to such Ineligible Holder and paid into a non-interest
bearing escrow account (which account shall not constitute a part of the Trust
Estate) maintained by the Trustee in respect of such Units for so long as the
Ineligible Holder continues to own such Units. Upon the disposition of such
Units by the Ineligible Holder to a party who is not an Ineligible Holder or
upon cancellation of the Certificates evidencing such Units pursuant to
paragraph (b) above, all cash distributions then held in escrow in respect of
such transferred Units shall be distributed to such Ineligible Holder.
SECTION 3.13 Filing of Registration Statements, Listing of Units.
(a) The Trustee shall, upon the request of Eastern States or
its successors in interest, on behalf of the Trust, cooperate with Eastern
States and otherwise use Best Efforts to cause:
(i) one or more Securities Act Registration Statements to be
prepared, signed, filed and declared effective by the Commission;
(ii) the Exchange Act Registration Statement to be prepared,
signed, filed and become effective;
(iii) the Units to be qualified or exempted from
qualification under the securities or Blue Sky laws of the
several states; and
(iv) the Units to be listed for trading on the NYSE or
another national securities exchange, as Eastern States shall
select, or, if listing on a national securities exchange is not
feasible or is undesirable, to cause the Units to be admitted for
quotation on the National Association of Securities Dealers
Automated Quotation System National Market System (the "NASDAQ").
(b) Eastern States shall be obligated and entitled, at its own
expense except as otherwise herein provided, to take or cause to be taken all
steps customary or appropriate to the accomplishment of the objectives set forth
in this Section 3.13 including, without limitation, engaging counsel for itself
and approving special counsel for the Trust, engaging accountants for the Trust,
contracting for all printing and engraving services, making all filings and
applications necessary to the foregoing and paying all filing and application
fees associated therewith. The Trustee shall execute, by and on behalf of the
Trust, any documents incidental or related to the foregoing objectives as
reasonably requested by Eastern States. Notwithstanding anything in this Section
3.13 to the contrary, unless required by the Commission, the Trustee shall not
be required
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to sign any Securities Act Registration Statement or Exchange Act Registration
Statement in connection with the initial public offering or any subsequent
offering of the Units. If the Trustee does not sign any Securities Act
Registration Statement or Exchange Act Registration Statement on behalf of the
Trust in connection with the initial public offering or any subsequent offering
of the Units by Eastern States, then Eastern States may sign on behalf of the
Trust.
(c) The reasonable fees, charges, expenses, disbursements and
other costs incurred by the Trustee or Delaware Trustee in connection with the
discharge of its duties pursuant to this Agreement including, without
limitation, trustee fees, engineering, audit and legal fees, printing and
mailing costs and amounts reimbursed or paid to Eastern States pursuant to
Section 3.06 hereof, shall be paid out of the Trust Estate as an administrative
expense of the Trust, provided that the organizational expenses of the Trust
shall be paid by Eastern States, except that the cost of legal counsel for the
Trustee, the Delaware Trustee, and the Trust (including legal fees incurred by
the Trustee or the Delaware Trustee in connection with the formation of the
Trust and issuance of Units) shall be paid out of the Trust Estate.
(d) After the registration of the Units pursuant to the
Exchange Act and/or the listing of the Units on the NYSE or another national
securities exchange or the quotation of the Units on the NASDAQ, the Trustee, on
behalf of the Trust, shall cause the Trust to comply with all of the rules,
orders and regulations of the Commission, such exchange or the National
Association of Securities Dealers, Inc., related to such registration, listing
or quotation, as the case may be, and take all such other reasonable actions
necessary for the Units to remain so registered, listed or quoted until the
Trust is terminated.
(e) The Trustee shall be empowered to, in connection with the
initial public offering of the Units or such other public offering of Units,
upon the request of Eastern States, in the name and on behalf of the Trust,
enter into any underwriting agreement for the purpose of causing the Trust to
provide certain warranties and agreement, including, without limitation,
providing, jointly and severally with Eastern States, indemnification in favor
of the underwriters and their control persons for material misstatements and
omissions made in connection with the public offering (and related contribution
agreements), and in connection therewith the Trustee shall upon the request of
Eastern States, provide certificates and other documents (provided that in no
event shall the Trustee be required to sign any registration statement under the
Securities Act or Exchange Act unless required to do so by the Commission) and
engage legal counsel to provide opinions of counsel reasonably requested by the
underwriters under such agreements; provided that the warranties and agreements
or obligations of the Trust under this paragraph (e) shall be limited solely to
the assets of the Trust and shall not result in the incurrence of any liability
by the Trustee or any Unitholder. In the event the Trustee does not sign such
underwriting agreement, Eastern States may sign on behalf of the Trust.
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SECTION 3.14 Reserve Report.
If a Reserve Report for the Royalty Interests is not provided by
Eastern States pursuant to Section 4.08 of the Conveyances, the Trustee shall
cause a Reserve Report for the Royalty Interests to be prepared by a firm of
independent petroleum engineers selected by the Trustee as of December 31 of
each year, in accordance with criteria established by the Commission showing
estimated proved oil and natural gas reserves attributable to the Royalty
Interests as of December 31 of such year and other reserve information required
in order for the Trustee to furnish the information required in Sections 5.03
and 5.04 of this Agreement. Such Reserve Report shall also show estimated future
net revenues and the net present value (discounted at 10 percent or such other
rate required by the Commission) of the estimated future net revenues
(calculated in accordance with criteria established by the Commission) of proved
reserves attributable to the Royalty Interests. The costs of such Reserve
Reports, whether provided by Eastern States or obtained by the Trustee, shall
constitute an administrative expense of the Trust payable out of the Trust
Estate pursuant to Section 3.07. Eastern States shall assist the Trustee in the
preparation of the Reserve Reports by furnishing all current and existing
reserve, production and geophysical data in its possession relating to the
Royalty Interests reasonably requested by or on behalf of the independent
petroleum engineers selected by the Trustee as necessary to prepare such Reserve
Reports; provided, that Eastern States shall not be required to disclose or
produce any information, documents or other materials which (a) were generated
for analysis or discussion purposes or contain interpretative data or (b) are
subject to the attorney-client or attorney-work product privileges, or any other
privileges to which Eastern States may be entitled pursuant to applicable law.
ARTICLE IV
TRUST UNITS AND BENEFICIAL INTEREST IN CERTIFICATES
SECTION 4.01 Creation and Distribution.
Ownership of the entire Beneficial Interest shall be divided into
10,500,000 Units. Except as otherwise provided in Section 3.12 hereof, the
ownership of the Units shall be evidenced by Certificates in the form attached
as Exhibit A hereto and evidenced by entry of a notation in an ownership ledger
maintained for such purpose by the Trustee. The Certificates issued by the
Trustee from time to time after the Closing may contain such changes of form,
but not substance, from the Certificates issued by the Trustee at Closing as the
Trustee, from time to time, deems necessary or desirable. Upon issuance in
accordance with this Agreement, the Units shall be validly issued, fully paid
and nonassessable. No Unit shall be entitled to preemptive or other similar
rights. The Unitholders shall be bound by the terms of the Agreement.
SECTION 4.02 Rights of Unitholders; Limitation on Personal Liability of
Unitholders.
Each Unit shall represent a pro rata undivided ownership of the
Beneficial Interest and shall entitle its holder to participate pro rata in the
rights and benefits of Unitholders under this
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Agreement. A Unitholder (whether by assignment or otherwise) shall take and
hold each Unit subject to all the terms and provisions of this Agreement and
the Conveyances, which shall be binding upon and inure to the benefit of the
successors, assigns, legatees, heirs and personal representatives of such
Unitholder. By an assignment or transfer of one or more Units, the assignor
thereby shall, with respect to such assigned or transferred Unit or Units, part
with, except as provided in Section 4.04 of this Agreement in the case of a
transfer after a Quarterly Record Date and prior to the corresponding payment
date, (i) all of his right, title and interest in and to such Unit or Units,
and (ii) all interests, rights and benefits of a Unitholder under the Trust and
this Agreement that are attributable to such Unit or Units as against all other
Unitholders, the Trust and the Trustee, including, without limiting the
generality of the foregoing, any and all rights to any Quarterly Distribution
Amounts, or any portion thereof, for any Quarterly Period or Quarterly Periods
subsequent to the Quarterly Period which relates to the last Quarterly Record
Date on which the assignor owned such Units. The Trust Units and the rights,
benefits and interests evidenced thereby are and, for all purposes (except for
tax purposes), shall be construed to be in all respects intangible personal
property, and the Trust Units shall be bequeathed, assigned, disposed of and
distributed as intangible personal property. No Unitholder as such shall have
any title, legal or equitable, in or to any real property interest or tangible
personal property interest that may be considered a part of the Trust Estate,
including, without limiting the foregoing, the Royalty Interests or any part
thereof, or in or to any asset of the Trust Estate to the extent that an
interest in such asset would cause the interest of a Unitholder to be treated
as other than an intangible personal property interest, but the sole interest
of each Unitholder shall be his ownership in the Beneficial Interest and the
obligation of the Trustee to hold, manage and dispose of the Trust Estate and
to account for the same as provided in this Agreement. No Unitholder shall have
the right to call for or demand or secure any partition or distribution of the
Royalty Interests or any other asset of the Trust Estate or any accounting
during the continuance of the Trust or during the period of liquidation and
winding up under Section 9.03 of this Agreement. Pursuant to Section 3803(a) of
the Business Act, the Unitholders shall be entitled, to the fullest extent
permitted by law, to the same limitation on personal liability as is extended
under the Delaware General Corporation Law to stockholders of private
corporations for profit.
SECTION 4.03 Execution of Certificates.
(a) Except as provided in (d) below, all Certificates shall be
signed by a duly authorized officer of the Trustee. Certificates may be signed
on behalf of the Trustee by such person who, as at the actual date of the
signing of such Certificates, is the proper officer of the Trustee, although at
the nominal date of such Certificates any such person was not such officer of
the Trustee. Any such signature may be the manual or facsimile signature (to the
extent permitted by law or the rules or regulations of any stock exchange on
which the Units are listed or admitted for trading) of such officers and may be
affixed, imprinted or otherwise reproduced on the Certificate.
(b) Pending the preparation of definitive Certificates, the
Trustee shall execute, and the transfer agent and registrar for the Units
appointed in accordance with Section 3.06 of this Agreement shall sign and
register, temporary Certificates, as directed in a certificate of an officer of
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Eastern States. Temporary Certificates may contain such references to any
provisions of this Agreement as may be appropriate. Every temporary Certificate
shall be executed by the Trustee and signed and registered upon the same
conditions and in substantially the same manner, and with like effect as the
definitive Certificates.
(c) As promptly as practicable, the Trustee shall execute and
furnish definitive Certificates and thereupon temporary Certificates may be
surrendered in exchange therefor without charge to the Unitholders at the
principal office of the transfer agent at which Certificates may be presented
for transfer pursuant to Section 4.04 hereof, and the Trustee (or the transfer
agent and registrar if an Entity other than the Trustee is serving in such
capacities) shall sign and register in exchange for such temporary Certificates
a like aggregate amount of definitive Certificates. Until so exchanged, the
temporary Certificates shall be entitled to the same benefits under this
Agreement as definitive Certificates.
(d) If Eastern States or the Trustee elects to issue Units in
global form through a depositary, the transfer agent is authorized to issue and
register the Units in accordance with the procedures of the depositary. Units
issued in global form shall be validly issued upon the receipt from the transfer
agent of a certificate stating that the Units have been duly issued and
registered in accordance with the directions of Eastern States or the Trustee.
SECTION 4.04 Registration and Transfer of Units; Lost and Destroyed
Certificates.
The Units shall be transferable as against the Trustee as provided
herein, and then only on the records of the Trustee and, except as provided in
Section 3.12 hereof, upon the surrender of Certificates, if any, and compliance
with such reasonable regulations as it may prescribe. No service charge shall be
made to the transferor or Transferee for any transfer of a Unit (or recordation
or registration thereof), but the Trustee may require payment of a sum
sufficient to cover any tax or other governmental charge that may be imposed in
relation thereto. Until any such registration of transfer is completed the
Trustee may treat the owner of any Unit as shown on its ownership ledger as the
owner of the Unit for all purposes and shall not be charged with notice of any
claim or demand respecting such Unit or the interest represented thereby by any
other party. Any such transfer of a Unit shall, as to the Trustee, transfer to
the Transferee as of the close of business on the date of transfer all of the
undivided right, title and interest of the transferor in and to the Beneficial
Interest in respect of such Unit, provided that a transfer of a Unit after any
Quarterly Record Date shall not transfer to the Transferee the right of any
transferor to any sum payable to him as the holder of the Unit of record on such
Quarterly Record Date. As to matters affecting the title, ownership, warranty or
transfer of Trust Units, Article 8 of the Uniform Commercial Code, the Uniform
Act for Simplification of Fiduciary Transfers and other statutes and rules with
respect to the transfer of securities, each as is adopted and then in force in
the State of Delaware, shall govern and apply. The death of any Unitholder shall
not entitle the Transferee of such Unitholder to an accounting or valuation for
any purpose, but such Transferee shall succeed to all rights of the deceased
Unitholder under this Agreement upon proper proof of title, satisfactory to the
Trustee.
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If any Certificate should become lost, stolen, destroyed or mutilated,
the Trustee, in its discretion and upon proof satisfactory to the Trustee,
together with a surety bond sufficient in the opinion of the Trustee to
indemnify the Trustee, the Delaware Trustee, and the Trust against all loss or
expenses in the premises, and, in the case of a mutilated Certificate, surrender
of the mutilated Certificate, may issue a new Certificate to the holder of such
lost, stolen, destroyed or mutilated Certificate as shown by the records of the
Trustee, upon payment of a reasonable charge of the Trustee and any reasonable
expenses incurred by it in connection therewith.
SECTION 4.05 Protection of Delaware Trustee and Trustee.
Each of the Delaware Trustee and the Trustee, and each Entity serving
in any such fiduciary capacity, shall be protected in acting or relying upon any
notice, certificate, assignment, opinion of counsel, report of certified public
accountant or any petroleum engineer or auditor or other expert, credential, or
any other document or instrument. Each of the Delaware Trustee and the Trustee,
and each Entity serving in any such fiduciary capacity, is specifically
authorized to rely upon the application of Article 8 of the Uniform Commercial
Code, the Uniform Act for Simplification of Fiduciary Security Transfers, and
the application of other statutes and rules with respect to the transfer of
securities, each as is adopted and then in force in the State of Delaware, as to
all matters affecting title, ownership, warranty or transfer of the Certificates
and Units, without any personal liability for such reliance, and the indemnity
granted under Section 6.02 of this Agreement shall specifically extend to any
matters arising as a result thereof. Further, and without limiting the
foregoing, each of the Delaware Trustee, the Trustee and each Entity serving in
either such capacity is specifically authorized and directed to rely upon the
validity of the Conveyance and the title held by the Trust in the Royalty
Interests pursuant thereto, and is further specifically authorized and directed
to rely upon opinions of counsel in each of the states in which the Underlying
Properties are located, without any liability in any capacity for such reliance.
SECTION 4.06 Determination of Ownership.
In the event of any disagreement between Persons claiming to be
Transferees of any Unit, the Trustee shall be entitled, in addition to other
rights which it may have under applicable law, at its option to refuse to
recognize any such claim so long as such disagreement shall continue. In so
refusing, the Trustee, and any Entity serving in such capacity, may elect to
make no disposition of the interest represented by the Unit involved, or any
part thereof, or of any sum or sums of money accrued or accruing thereunder,
and, in so doing, the Trustee shall not be or become liable to any Person for
the failure or refusal of the Trustee to comply with such conflicting claims,
and shall be entitled to continue so to refrain and refuse so to act, until:
(a) the rights of the adverse claimants have been adjudicated
by arbitration (pursuant to Article XI) or by a final nonappealable judgment of
a court assuming and having jurisdiction of the parties and the interest and
money involved, or
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(b) all differences have been resolved by valid agreement
between said parties and the Trustee shall have been notified thereof in writing
signed by all of the interested parties.
ARTICLE V
ACCOUNTING AND DISTRIBUTION; REPORTS
SECTION 5.01 Fiscal Year and Accounting Method.
The Trustee shall adopt for the Trust the calendar year as its fiscal
year. The Trustee shall maintain its books in accordance with generally accepted
accounting principles or such other method as will provide appropriate financial
data responsive to the needs of the Unitholders and which shall comply with
Section 5.03 and 5.04.
SECTION 5.02 Quarterly Distributions.
At least 12 calendar days prior to each Quarterly Record Date, Eastern
States shall notify the Trustee of Eastern States estimate of the cash to be
received by the Trust attributable to the Royalty Interests during the Quarterly
Period to which such Quarterly Record Date pertains. At least 10 calendar days
(or such longer period of time as may be required by the rules of any securities
exchange on which the Units are listed or admitted to trading), prior to each
Quarterly Record Date the Trustee shall communicate to the Unitholders its
determination of the Quarterly Distribution Amount for the relevant Quarterly
Period, assuming that the amount of cash estimated by Eastern States to be
received by the Trust attributable to the Royalty Interests is actually received
by the Trust in a timely fashion and including the amount of interest estimated
by the Trustee to be earned on such cash proceeds during the period held by the
Trust. Any excess of interest actually earned on such Quarterly Distribution
Amount over the interest expected to be earned thereon shall be included in the
next computed Quarterly Distribution Amount. Any deficit in interest actually
earned compared to interest expected to be earned shall be made up from other
assets of the Trust, and the cost of so doing shall be treated as an
administrative expense of the Trust for the Quarterly Period in which the
deficit is realized. The Trustee shall request from the Transfer Agent its list
of Unitholders as of the close of business on each Quarterly Record Date for the
purpose of determining the Unitholders entitled to receive the Quarterly
Distribution Amount in respect of such Quarterly Period. On or prior to the 25th
day of the third calendar month after the end of each Quarterly Period during
the term of the Trust, the Trustee shall, subject to Section 3.12 hereof,
distribute to the Unitholders pro rata the Quarterly Distribution Amount with
respect to such Quarterly Period, together with an amount previously determined
by the Trustee pursuant to this Section 5.02 as that amount of interest expected
to be earned on each such amount from the date of receipt thereof by the Trustee
to the payment date, to Unitholders of record on the Quarterly Record Date for
such Quarterly Period.
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SECTION 5.03 Income Tax Reporting.
For federal or state income tax purposes, the Trustee shall file for
the Trust such returns and statements as the Trustee is advised are required to
comply with applicable provisions of (i) the Code or any successor statute or
statutes and the regulations thereunder and (ii) any applicable state laws or
regulations thereunder, in either case to permit each Unitholder to make all
calculations reasonably necessary for tax purposes. The Trustee is authorized
and directed to treat all income, credits and deductions of the Trust for each
Quarterly Period as having been realized on the Quarterly Record Date for such
Quarterly Period unless otherwise advised by counsel or the Internal Revenue
Service.
SECTION 5.04 Reports to Unitholders and Others.
(a) Within 120 days following the end of each fiscal year or
such shorter period of time as may be required by the rules of any securities
exchange on which the Units are listed for trading, the Trustee shall mail to
each Person who was a Unitholder of record on a date to be selected by the
Trustee an annual report, containing financial statements audited by a
nationally recognized firm of independent public accountants selected by the
Trustee, and such annual reserve information regarding the Royalty Interests as
may be required by any regulatory authority having jurisdiction.
(b) Promptly after receipt of the requisite information and no
later than the 15th day of February in each calendar year, the Trustee shall
prepare and mail to Unitholders of record on each of the four preceding
Quarterly Record Dates occurring during the prior calendar year, such report or
reports as may be necessary to permit each Unitholder to make all calculations
reasonably necessary for federal and state tax purposes for the preceding
calendar year or any Quarterly Period thereof, including depletion.
(c) The Trustee is authorized to make and shall take all
reasonable actions necessary to make all Exchange Act filings on behalf of the
Trust with the Commission. It is the intention of Eastern States that the Units
be listed for trading on the NYSE, Inc. and, in this regard, Eastern States
shall advise the Trustee of any actions (consistent with the purposes of the
Trust) that the Trustee should take in connection with the effectuation of such
listing. If listing is accomplished, the Trustee shall take all reasonable
actions necessary to maintain such listing including compliance with the stock
exchange's rules and the filing of any reports required by the stock exchange.
Eastern States shall prepare and file all filings and reports required under the
Securities Act or state securities or Blue Sky laws.
(d) In addition, the Trustee is authorized to make, and the
Trustee shall take, all reasonable action to prepare and mail to the Unitholders
any reports, press releases or statements, financial or otherwise, that Eastern
States notifies the Trustee are required to be provided by the Trustee to
Unitholders by law or governmental regulation or the requirements of any
securities exchange on which the Units are listed or admitted to trading.
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(e) Notwithstanding any time limit imposed by paragraph (a) or
(b) of this Section 5.04, if, due to a delay in receipt by the Trustee of
information necessary for preparation of a report or reports required by such
paragraphs, the Trustee shall be unable to prepare and mail such report or
reports within such time limit, the Trustee shall prepare and mail such report
or reports as soon thereafter as practicable.
SECTION 5.05 Information to be Supplied by Eastern States and Trustee.
Eastern States shall provide, or cause to be provided, to the Trustee
on a timely basis such information as is not known to the Trustee or is
otherwise more easily available to Eastern States than to the Trustee concerning
the Royalty Interests (including information with respect to the Underlying
Properties owned by Eastern States or any of its affiliates) and related matters
as shall be necessary to permit the Trustee to comply with respect to the Trust
with the reporting obligations of the Trust pursuant to the Exchange Act, the
requirements of any securities exchange on which the Units are listed or
admitted to trading and this Agreement and for any other reasonable purpose of
the Trust. The Trustee shall provide to Eastern States, within 15 days after the
end of each calendar quarter, a written itemized report showing each
administrative cost of the Trust paid or payable for such quarter (including,
but not limited to, each out-of-pocket expenditure, all trustee compensation and
the administrative services fee paid to Eastern States). In addition, Eastern
States shall provide to the Trustee, for use in connection with the Trust's Form
10-K annual report, a "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
ARTICLE VI
LIABILITY OF DELAWARE TRUSTEE AND TRUSTEE AND
METHOD OF SUCCESSION
SECTION 6.01 Liability of Delaware Trustee and Trustee.
(a) Notwithstanding any other provision of this Agreement,
each of the Delaware Trustee and the Trustee, in carrying out its powers and
performing its duties, may act in its discretion, at the expense of the Trust,
through agents or attorneys pursuant to agreements entered into with any such
Entity. Each Entity serving in such capacity shall be personally or individually
liable only for fraud or acts or omissions in bad faith or which constitute
gross negligence and shall not otherwise be individually or personally liable
for any act or omission of any agent or employee unless acting in bad faith or
with gross negligence in the selection and retention of such agent or employee.
No Entity serving as Trustee or Delaware Trustee shall be individually liable by
reason of any act or omission of any other Entity serving as Trustee or Delaware
Trustee.
(b) If the Trustee enters into a contract on behalf of the
Trust or Trust Estate without ensuring that any liability arising out of such
contract shall be satisfiable only out of the Trust Estate and shall not in any
event, including the exhaustion of the Trust Estate, be satisfiable out of
amounts at any time distributed to any Unitholder or out of any other assets
owned by any
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Unitholder, then the Trustee vis-a-vis the Unitholders, shall be fully and
exclusively liable for such liability, but shall have the right to be
indemnified and reimbursed from the Trust Estate to the extent provided in
Section 6.02.
SECTION 6.02 Indemnification of Trustee and Delaware Trustee..
(a) Each Entity serving as the Delaware Trustee or the
Trustee, as well as each of their officers, directors, employees and agents
(including Eastern States and any of its Affiliates when acting as agents),
shall be indemnified and held harmless by, and receive reimbursement from, the
Trust Estate against and from any and all liabilities, expenses, claims, damages
or losses incurred by it, individually and as trustee, in the administration of
the Trust and the Trust Estate or any part or parts thereof, or in the doing of
any act done or performed, or in any omission occurring, on account of its being
trustee, except such liabilities, expenses, claims, damages or losses as to
which it is liable under Section 6.01 of this Agreement (it being understood
that each Entity serving as the Delaware Trustee or the Trustee shall be
indemnified and held harmless by, and receive reimbursement from, the Trust
Estate against such Entity's own negligence which does not constitute gross
negligence). Each Entity serving as the Delaware Trustee or the Trustee shall
have a first lien upon the Trust Estate to secure it for such indemnification
and reimbursement and for compensation to be paid to such Entity. Neither the
Delaware Trustee nor the Trustee nor any Entity serving in either of such
capacities, nor any agent or employee thereof shall be entitled to any
reimbursement or indemnification from any Unitholder for any liabilities,
expenses, claims, damages or losses incurred by the Delaware Trustee or the
Trustee or any such Entity, agent or employee, except as provided in the second
paragraph of Section 4.04 of this Agreement, their right of reimbursement and
indemnification, if any, being limited solely to the Trust Estate, whether or
not the Trust Estate is exhausted without full reimbursement or indemnification.
All legal or other expenses reasonably incurred by the Trustee or Delaware
Trustee in connection with the investigation or defense of any loss, claim,
damage, liability or action in which such trustee is entitled to indemnity under
this Section 6.02(a) shall be paid out of the Trust Estate. This Section 6.02(a)
is in addition to any right(s) to indemnification available under Section
3.13(f).
(b) Eastern States shall indemnify and hold harmless each of
the Delaware Trustee and the Trustee, individually and as trustee, against any
losses, claims, damages or liabilities, to which such trustee may become
subject, under or with respect to the Securities Act, the Exchange Act, any
other federal or state securities law or otherwise, insofar as such losses,
claims, damages or liabilities (or actions in respect thereof) arise out of, are
based upon or are connected with an untrue statement or alleged untrue statement
of a material fact contained in, or an omission or alleged omission of a
material fact from, (i) the Securities Act Registration Statement, any
preliminary prospectus, the final prospectus, or any amendment or supplement
thereto, or (ii) any other filing, report or other action taken in respect to
the Securities Act, the Exchange Act or any other federal or state securities
law, the listing of the Units on the NYSE or another national securities
exchange or the quotation of the Units on NASDAQ; provided, however, that
Eastern States shall not be liable to the Trustee or Delaware Trustee,
individually or as trustees, in any such case under the preceding clause (i) of
this Section 6.02(b) to the extent that any such loss, claim, damage or
liability arises out
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of, is based upon or is connected with information furnished by the Trustee or
the Delaware Trustee expressly for use in the Securities Act Registration
Statement, any preliminary prospectus, the final prospectus or any amendment or
supplement thereto; and provided, further, however, that Eastern States shall
not be liable to the Trustee or the Delaware Trustee, individually or as
trustees, in any such case under the preceding clause (ii) of this Section
6.02(b) to the extent that any such loss, claim, damage or liability arises out
of, is based upon or is connected with information prepared or furnished by the
Trustee or the Delaware Trustee if the Trustee and the Delaware Trustee have
been adjudicated by a final nonappealable judgment of a court of competent
jurisdiction to have acted in bad faith or with gross negligence. Subject to
Section 6.02(d) hereof, Eastern States shall reimburse the Trustee and the
Delaware Trustee for any legal or other expenses reasonably incurred by such
trustee in connection with the investigation or defense of any loss, claim,
damage, liability or action in which such trustee is entitled to indemnity by
Eastern States hereunder.
(c) Eastern States shall indemnify and hold harmless each of
the Trustee and the Delaware Trustee, individually and as trustee, against any
losses, claims, damages or liabilities to which such trustee may become subject,
under or with respect to any of the Environmental Laws, insofar as such losses,
claims, damages or liabilities (or actions in respect thereof) arise out of, are
in connection with, or are based upon the Underlying Properties, except for
losses, claims, damages or liabilities arising from any acts of such trustee not
contemplated hereunder. The obligations of Eastern States hereunder may be
assigned or transferred to any Entity acquiring the Underlying Property to which
each loss, claim, damage or liability relates provided such Entity (or any
Entity guaranteeing the obligations hereunder of such Entity) unconditionally
agrees in writing, reasonably satisfactory to the Trustee, to assume Eastern
States' obligations under this Section 6.02(c). In the event Eastern States
assigns its obligations hereunder as permitted above, the provisions of Section
6.02(d) of this Agreement shall govern the indemnification obligation of the
transferee. Subject to Section 6.02(d) hereof, Eastern States shall reimburse
the Trustee and the Delaware Trustee for any legal or other expenses reasonably
incurred by such trustee in connection with the investigation or defense of any
loss, claim, damage, liability or action for which such trustee is entitled to
indemnity by Eastern States hereunder.
(d) If any action or proceeding shall be brought or asserted
against the Trustee or Delaware Trustee (each referred to as an "Indemnified
Party" and, collectively, the "Indemnified Parties") in respect of which
indemnity may be sought from Eastern States (herein referred to as the
"Indemnifying Party") pursuant to Section 6.02(b) or Section 6.02(c) hereof, of
which the Indemnified Party shall have received notice, the Indemnified Party
shall promptly notify the Indemnifying Party in writing, and the Indemnifying
Party shall assume the defense thereof, including the employment of counsel
reasonably satisfactory to the Indemnified Party and the payment of all
expenses. The Indemnified Party shall have the right to employ separate counsel
in any such action and to participate in the defense thereof, but the fees and
expenses of such counsel shall be at the expense of the Indemnified Party unless
(i) the Indemnifying Party has agreed to pay such fees and expenses; (ii) the
Indemnifying Party shall have failed to assume the defense of such action or
proceeding and employ counsel reasonably satisfactory to the Indemnified Party
on any such action or proceeding; or (iii) the named parties to any such action
or proceeding include both
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the Indemnified Party and the Indemnifying Party, and the Indemnified Party
shall have been advised by counsel that there may be one or more legal defenses
available to such trustee that are different from or additional to those
available to the Indemnifying Party (in which case, if the Indemnified Party
notifies the Indemnifying Party in writing that it elects to employ separate
counsel at the expense of the Indemnifying Party, the Indemnifying Party shall
not have the right to assume the defense of such action or proceeding on behalf
of the Indemnified Party and the Indemnified Party may employ such counsel for
the defense of such action or proceeding as is reasonably satisfactory to the
Indemnifying Party; it being understood, however, that the Indemnifying Party
shall not, in connection with any one such action or proceeding or separate but
substantially similar or related actions or proceedings in the same jurisdiction
arising out of the same general allegations or circumstances, be liable for the
fees and expenses of more than one separate firm of attorneys for the
Indemnified Parties at any time). The Indemnifying Party shall not be liable for
any settlement of any such action or proceeding effected without the written
consent of the Indemnifying Party, but, if settled with such written consent, or
if there be a final judgment for the plaintiff in any such action or proceeding,
the Indemnifying Party agrees (to the extent stated above) to indemnify and hold
harmless the Indemnified Party from and against any loss or liability by reason
of such settlement or judgment.
(e) Any losses, claims, damages or liabilities for which any
Entity serving as the Trustee or the Delaware Trustee may be entitled to
indemnification under this Section 6.02 shall be first satisfied out of the
Trust Estate pursuant to Section 6.02(a) prior to any indemnification from
Eastern States, except for environmental liabilities arising out of or relating
to activities occurring on, or in connection with, or conditions existing on or
under, the Underlying Properties before September 1, 1999 which, pursuant to the
terms of the Conveyances, are required to be borne by Eastern States and not the
Trust; provided, Eastern States shall be required to provide such
indemnification at any time and from time to time that cash in the Trust Estate
or cash reasonably anticipated to be available is inadequate to satisfy and
discharge such claims, damages or liabilities.
(f) The obligations of the Trust and Eastern States under this
Section shall survive the resignation or removal of the Trustee or the Delaware
Trustee and, in the case of Eastern States, the termination of the Trust and
this Agreement. SECTION 6.03 Resignation of Delaware Trustee and Trustee.
SECTION 6.03 Resignation of Delaware Trustee and Trustee
Any Entity serving as the Delaware Trustee or the Trustee may resign,
as such, with or without cause, at any time by written notice to Eastern States,
to any other Entity serving as the Delaware Trustee or the Trustee, and to each
of the then Unitholders of record in accordance with Section 11.08 of this
Agreement. Such notice shall specify a date when such resignation shall take
effect, which shall be a Business Day not less than 60 days after the date such
notice is mailed; provided, however, that in no event shall any resignation of
the Trustee be effective until a successor Trustee has accepted its appointment
as Trustee pursuant to the terms hereof; and provided, further, that in no event
shall any resignation of the Delaware Trustee be effective until a successor
Delaware Trustee has accepted its appointment as Delaware Trustee pursuant to
the terms hereof.
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SECTION 6.04 Removal of Delaware Trustee and Trustee.
(a) Each Entity serving as the Delaware Trustee or the Trustee
may be removed as trustee hereunder, with or without cause, at a meeting held in
accordance with the requirements of Article VIII, provided that any removal of
the Delaware Trustee shall be effective only at such time as a successor
Delaware Trustee, fulfilling the requirements of Section 3807(a) of the Business
Act, has been appointed and has accepted such appointment, and provided,
further, that any removal of the Trustee shall be effective only at such time as
a successor Trustee has been appointed and has accepted such appointment.
(b) The Trustee may be removed as trustee hereunder by Eastern
States, in its sole discretion, in the event that the Trustee fails for two
years in any three year period to prepare and mail to Unitholders of record on
each of the four preceding Quarterly Record Dates occurring during the prior
calendar year, such reports as are required by Section 5.04(b), provided that
any removal shall be effective only at such time as Easter States, in its sole
discretion, has appointed a successor Trustee and such successor Trustee has
accepted such appointment.
SECTION 6.05 Appointment of Successor Delaware Trustee or Trustee.
In the event of the resignation or removal of the Entity serving as the
Delaware Trustee or the Trustee or if any such Entity has given notice of its
intention to resign as the Delaware Trustee or the Trustee, the Unitholders
represented at a meeting held in accordance with the requirements of Article
VIII may appoint a successor trustee. Nominees for appointment may be made by
(i) the resigned, resigning or removed trustee or (ii) any Unitholder or
Unitholders owning (beneficially or of record) at least 15% of the then
outstanding Units. Any successor of the Trustee shall be a bank or trust company
having capital, surplus and undivided profits of at least $100,000,000. Any
successor to the Delaware Trustee shall be a bank or trust company having its
principal place of business in the State of Delaware and having capital,
surplus, and undivided profits of at least $20,000,000. If a vacancy in the
position of either the Trustee or the Delaware Trustee continues for 60 days
after the notice of resignation or occurrence of a vacancy, a successor may be
appointed by any State or Federal District Court having jurisdiction in New
Castle County, Delaware, upon the application of any Unitholder, Eastern States
or the Entity tendering its resignation as either the Trustee or the Delaware
Trustee filed with such court, and in the event any such application is filed,
such court may appoint a temporary Trustee or Delaware Trustee at any time after
such application is filed, which shall, pending the final appointment of a
Trustee or Delaware Trustee, have such powers and duties as the court appointing
such temporary Trustee or Delaware Trustee shall provide in its order of
appointment, consistent with the provisions of this Agreement. Any such
temporary Trustee or Delaware Trustee need not meet the minimum standards of
capital, surplus and undivided profits otherwise required of a successor Trustee
or Delaware Trustee under this Section 6.05. Nothing herein shall prevent the
same Entity from serving as both the Delaware Trustee and the Trustee if it
meets the qualifications thereof.
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Immediately upon the appointment of any successor Trustee or Delaware
Trustee, any rights, titles, duties, powers and authority of the succeeded
Trustee or Delaware Trustee hereunder (except to the rights to amounts payable
under Article VII hereof accruing through the appointment of such successor
Trustee or Delaware Trustee) shall be vested in and undertaken by the successor
Trustee or Delaware Trustee, which shall be entitled to receive from its
predecessor all of the Trust Estate held by it hereunder and all records and
files of its predecessor necessary in connection therewith. Any resigning or
removed Trustee or Delaware Trustee shall account to its successor for its
administration of the Trust. All successor trustees shall be fully protected in
relying upon such accounting and no successor Trustee or Delaware Trustee shall
be obligated to examine or seek alteration of any account of any preceding
Trustee or Delaware Trustee, nor shall any successor Trustee or Delaware Trustee
be liable personally for failing to do so or for any act or omission of any
preceding Trustee or Delaware Trustee. The preceding sentence shall not prevent
any successor Trustee or Delaware Trustee or anyone else from taking any action
otherwise permissible in connection with any such account.
SECTION 6.06 Laws of Other Jurisdictions.
If, notwithstanding the other provisions of this Agreement (including,
without limitation, Section 11.06 hereof), the laws of jurisdictions other than
the State of Delaware (each being referred to below as "such jurisdiction")
apply to the administration of properties under this Agreement, the following
provisions shall apply. If it is necessary or advisable for a trustee to serve
in such jurisdiction and if the Trustee is disqualified from serving in such
jurisdiction or for any other reason fails or ceases to serve there, the
ancillary trustee in such jurisdiction shall be such Entity, which need not meet
the requirements set forth in the third sentence of Section 6.05 of this
Agreement, as shall be designated in writing by the Trustee. To the extent
permitted under the laws of such jurisdiction, the Trustee may remove the
trustee in such jurisdiction, without cause and without necessity of court
proceeding, and may or may not appoint a successor trustee in such jurisdiction
from time to time. The trustee serving in such jurisdiction shall, to the extent
not prohibited under the laws of such jurisdiction, appoint the Trustee to
handle the details of administration in such jurisdiction. The trustee in such
jurisdiction shall have all rights, powers, discretions, responsibilities and
duties as are delegated in writing by the Trustee, subject to such limitations
and directions as shall be specified by the Trustee in the instrument evidencing
such appointment. Any trustee in such jurisdiction shall be responsible to the
Trustee for all assets with respect to which such trustee is empowered to act.
To the extent the provisions of this Agreement and Delaware law cannot be made
applicable to the administration in such jurisdiction, the rights, powers,
duties and liabilities of the trustee in such jurisdiction shall be the same (or
as near the same as permitted under the laws of such jurisdiction if applicable)
as if governed by Delaware law. In all events, the administration in such
jurisdiction shall be as free and independent of court control and supervision
as permitted under the laws of such jurisdiction. The fees and expenses of any
ancillary trustee shall constitute an administrative expense of the Trust
payable from the Trust Estate. Whenever the term "Trustee" is applied in this
Agreement to the administration in such jurisdiction, it shall refer only to the
trustee then serving in such jurisdiction.
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SECTION 6.07 Reliance on Experts.
The Trustee and the Delaware Trustee may, but shall not be required to,
consult with counsel (who may be counsel to Eastern States unless Eastern States
otherwise notifies the Trustee or Delaware Trustee in writing), accountants,
geologists, engineers and other parties deemed by the Trustee or the Delaware
Trustee to be qualified as experts on the matters submitted to them, and the
opinion of any such party on any matter submitted to it by the Trustee or the
Delaware Trustee shall be full and complete authorization and protection in
respect of any action taken or suffered by the Trustee or the Delaware Trustee
hereunder in good faith in reliance upon and in accordance with the opinion of
any such party. Each of the Trustee and Delaware Trustee is authorized to make
payments of all reasonable fees for services or expenses thus incurred out of
the Trust Estate.
SECTION 6.08 Failure of Action by Eastern States.
In the event that Eastern States shall fail or be unable to take any
action as required under any provision of this Agreement, the Trustee is
empowered to take such action.
SECTION 6.09 Force Majeure.
The Trustee and the Delaware Trustee shall not incur any liability to
any holder of a Unit if, by reason of any current or future law or regulation
thereunder of the federal government or any other governmental authority, or by
reason of any act of God, war or other circumstance beyond its control, the
Trustee or the Delaware Trustee is prevented or forbidden from doing or
performing any act or thing required by the terms hereof to be done or
performed; nor shall the Trustee or the Delaware Trustee incur any liability to
any holder of a Unit by reason of any nonperformance or delay caused as
aforesaid in the performance of any act or thing required by the terms hereof to
be done or performed, or by reason of any exercise of, or failure to exercise,
any discretion provided for herein.
ARTICLE VII
COMPENSATION OF THE TRUSTEE AND DELAWARE TRUSTEE
SECTION 7.01 Compensation of Trustee and Delaware Trustee.
The Bank, in its capacity as the initial Trustee, and Bank One
Delaware, in its capacity as the initial Delaware Trustee, shall be compensated
for their services in accordance with the terms of a separate agreement.
Entities serving as the Trustee and Delaware Trustee hereunder shall be
reimbursed for all actual expenditures made in connection with administration of
the Trust, including those made on account of any unusual duties in connection
with matters pertaining to the Trust. Any unusual or extraordinary services
rendered by the Entity serving as Trustee or by the Entity serving as Delaware
Trustee in connection with the administration of the Trust shall be treated as
trustee administrative services for purpose of computing the respective
administrative fee to be paid to each Entity serving as trustee hereunder.
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SECTION 7.02 Source of Funds.
All compensation, reimbursements and other charges owing to any Entity
as a result of its service as trustee hereunder shall be payable by the Trust
out of the Trust Estate and such Entity shall have a first lien on the Trust
Estate for payment of such compensation, reimbursements and other charges.
SECTION 7.03 Ownership of Units by Eastern States, the Trustee and Delaware
Trustee.
Each of the Trustee and the Delaware Trustee, in its individual or
other capacity, may become the owner or pledgee of Units with the same rights it
would have if it were not a trustee hereunder. Eastern States and each of its
Affiliates may become the owner of Units with the same rights and entitled to
the same benefits as any other Unitholder.
ARTICLE VIII
MEETINGS OF UNITHOLDERS
SECTION 8.01 Purpose of Meetings.
A meeting of the Unitholders may be called at any time and from time to
time pursuant to the provisions of this Article VIII to transact any matter that
the Unitholders may be authorized to transact.
SECTION 8.02 Call and Notice of Meetings.
Any meeting of the Unitholders may be called by the Trustee or by
Unitholders owning of record not less than 15% in number of the then outstanding
Units. The Delaware Trustee may call such a meeting but only for the purpose of
appointing a successor to it upon its resignation. All such meetings shall be
held at such time and at such place in Fort Worth, Texas, as the notice of any
such meeting may designate. Except as may be otherwise required by applicable
law or by any securities exchange on which the Units are listed for trading,
written notice of every meeting of the Unitholders signed by the Trustee or the
Unitholders calling the meeting (or the Delaware Trustee if calling the
meeting), setting forth the time and place of the meeting and in general terms
the matters proposed to be acted upon at such meeting, shall be given in person,
by mail or electronic publication not more than 60 nor less than 20 days before
such meeting is to be held to all of the Unitholders of record on a record date
selected by the Trustee (the "Record Date Unitholders") which shall be not more
than 60 days before the date of such mailing. If such notice is given to any
Unitholder by mail, it shall be directed to him at his last address as shown by
the ownership ledger of the Trustee and shall be deemed duly given when so
addressed and deposited in the United States mail, postage paid. No matter other
than that stated in the notice shall be acted upon at any meeting. Only
Unitholders of record at the close of business on the record date selected by
the Trustee for such meeting shall be entitled to notice of and to exercise
rights at or in connection with the meeting.
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SECTION 8.03 Method of Voting and Vote Required.
Each Record Date Unitholder shall be entitled to one vote for each Unit
owned by him, and any Record Date Unitholder may vote in person, by duly
executed written proxy, electronic publication or by written consent. At any
such meeting, the presence in person or by proxy of Record Date Unitholders
holding a majority of the Units held by all Record Date Unitholders shall
constitute a quorum, and, except as otherwise provided herein, any matter shall
be deemed to have been approved by the Record Date Unitholders (including, but
not limited to, appointment of a successor trustee) if it is approved by the
vote of Record Date Unitholders holding more than 50% of the Units represented
at the meeting, although less than a majority of all of the Units at the time
outstanding, except that the affirmative vote by Record Date Unitholders of
66 2/3% or more of all the Units then outstanding shall be required to:
(a) approve any amendment to or affecting this Agreement other
than (i) amendments prohibited by Section 10.01, (ii) amendments to Section 9.02
or 9.03 (which shall require the written consent of Eastern States and the
affirmative vote by the Unitholders of not less than 66 2/3% of all then
outstanding Units), and (iii) any amendment to or affecting this Agreement to
the extent permitted pursuant to Section 10.02 of this Agreement (which shall
not require Unitholder approval);
(b) approve or authorize the sale of Royalty Interests of which
the aggregate standardized measure exceeds $30 million in accordance with
Section 3.02(a) (excluding sales or dispositions made in accordance with
Sections 3.02(b), 3.05, 3.09 or 9.03);
(c) remove the Delaware Trustee or the Trustee; or
(d) dissolve the Trust.
SECTION 8.04 Conduct of Meetings.
The Trustee may make such reasonable regulations consistent with the
provisions hereof as it may deem advisable for any meeting of the Unitholders,
for electronic or other means of voting, for the appointment of proxies, and in
regard to the appointment and duties of inspectors of votes, the submission and
examination of proxies, Certificates and other evidence of the right to vote,
the preparation and use at the meeting of a list certified by or on behalf of
the Trustee of the Unitholders entitled to vote at the meeting and such other
matters concerning the conduct of the meeting as it shall deem advisable.
SECTION 8.05 Unitholder Proposals.
In the event a meeting of Unitholders is called for any purpose at the
request of any Unitholder or Unitholders pursuant to the provisions of this
Article VIII, the Unitholder or Unitholders requesting such meeting shall be
required to prepare and file a proxy statement with the
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Commission and the NYSE regarding such meeting in satisfaction of all applicable
Commission and NYSE rules and regulations and at the expense of such requesting
Unitholder or Unitholders. The Unitholder or Unitholders requesting such meeting
shall bear the expense of distributing to Unitholders the notice of meeting and
the proxy statement related thereto. The Trustee shall cooperate in the
preparation of any such proxy statement and any related materials and shall
provide such information for inclusion therein as and to the extent reasonably
necessary at the expense of the Trust.
ARTICLE IX
DURATION, REVOCATION AND TERMINATION OF TRUST
SECTION 9.01 Revocation.
Subject to the third sentence of this Section 9.01, the Trust is and
shall be irrevocable and Eastern States, as trustor, after Closing, retains no
power to alter, amend or terminate the Trust except as set forth herein and in
Section 10.02 of this Agreement. The Trust shall be terminable only as provided
in Section 9.02 of this Agreement, and shall continue until so terminated. Prior
to the Closing, Eastern States may revoke the Trust by written notice to the
Trustee in which event the Trustee shall reconvey, the Trust Estate, less any
expenses or liabilities of the Trust, to Eastern States.
SECTION 9.02 Dissolution.
The Trust shall dissolve upon the first to occur of the following
events:
(a) the disposition by the Trust of all Royalty Interests
pursuant to this Agreement;
(b) following an affirmative vote in favor of dissolution of the
Trust by the holders of record of not less than 66 2/3% of the then outstanding
Units at a meeting duly called and held in accordance with the requirements of
Article VIII hereof;
(c) such time as (i) the annual Net Proceeds paid to the Trust in
respect of the Conveyance burdening the Underlying Properties located in West
Virginia are less than $3.5 million for each of two consecutive calendar years
after the year 2000 or (ii) the annual Net Proceeds paid to the Trust in respect
of the Conveyance burdening the Underlying Properties located in Kentucky are
less than $3.5 million for each of the two consecutive calendar years such
consecutive calendar years occur after calendar year 2000;
(d) Eastern States exercises its conditional right of repurchase
pursuant to Section 9.04 hereof; and
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(e) a judicial dissolution of the Trust occurs.
SECTION 9.03 Disposition and Distribution of Assets and Properties.
(a) Notwithstanding the dissolution of the Trust pursuant to
Section 9.02 of this Agreement, the Delaware Trustee and the Trustee shall
continue to act as the trustees of the Trust Estate and as such shall exercise
the powers granted under this Agreement until their duties have been fully
performed and the Trust Estate finally distributed so that the affairs of the
Trust may be liquidated and wound up in accordance with this Agreement and
Section 3808 of the Business Act. Following the completion of winding-up of the
Trust, the Trustee shall file a Certificate of Cancellation in accordance with
Section 3810(d) of the Business Act and thereupon the Trust shall terminate.
(b) Within 5 Business Days following the Termination Date, the
Trustee shall provide Eastern States and the Delaware Trustee with written
notice of dissolution of the Trust and shall engage an investment banking firm
(the "Advisor"), on behalf of the Trust, to assist the Trustee in selling the
remaining Royalty Interests then owned by the Trust (the "Remaining Royalty
Interests"), which assistance shall include, but not be limited to (i) valuing
the Remaining Royalty Interests owned by the Trust, (ii) evaluating offers to
purchase the Remaining Royalty Interests, (iii) seeking buyers for the Remaining
Royalty Interests, and (iv) rendering the fairness opinions required by this
Section 9.03 and otherwise as may be requested by the Trustee.
(c) As promptly as practicable after the engagement by the Trust
of the Advisor, the Trustee, based on the advice and with the assistance of the
Advisor, shall use its Best Efforts to sell the Remaining Royalty Interests and
to obtain offers for the Remaining Royalty Interests. Such sale shall be
conducted in such manner and in accordance with such procedures as the Trustee
concludes, based upon the advice of the Advisor, are most likely to produce the
highest aggregate value to the Trust for the Remaining Royalty Interests.
Eastern States shall have the right, but not the obligation, to participate in
such sale as a bidder for any or all of the Remaining Royalty Interests (or any
part or parcel thereof). The Trustee's evaluation of each offer for the
Remaining Royalty Interests (or any portion thereof) shall be based on an
evaluation of such offer by the Advisor, and the Trustee shall accept the offer
or offers therefor that, based on the evaluation thereof by the Advisor,
constitute the highest offer or offers and are likely to be consummated within a
time period determined by the Advisor to be reasonable. If acceptable offers are
not received for all of the Remaining Royalty Interests, the Trustee may request
Eastern States to submit an offer for the Remaining Royalty Interests (or the
portion or portions thereof for which acceptable offers were not received) for
consideration by the Trustee. If Eastern States makes such an offer and the
Trustee accepts it, such acceptance shall be conditioned upon receipt, prior to
closing of the sale, of an opinion of the Advisor, in form satisfactory to the
Trustee, of the fairness of the offer to the Trust and Unitholders from a
financial point of view. The Trustee shall each use its Best Efforts to close
the purchase or purchases of the Remaining Royalty Interests within 30 days
after a definitive purchase agreement for same is executed with each successful
bidder (or as promptly thereafter as practicable).
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(d) Any Person purchasing the Remaining Royalty Interests,
pursuant to the procedures set forth in Section 9.03(c) hereof, regardless of
the date of closing of the purchase, shall be entitled to all proceeds of
production attributable to the Remaining Royalty Interests after the Termination
Date and neither the Trust nor the Unitholders shall be entitled to any such
proceeds. Eastern States shall deposit all proceeds of production following the
Termination Date payable to the Trust pursuant to the Conveyance into a
non-interest bearing account and, upon closing of the sale of the Remaining
Royalty Interests, shall pay all deposited amounts to the buyer of the Remaining
Royalty Interests.
(e) If all Remaining Royalty Interests are not, for any reason,
sold or a definitive agreement for sale thereof entered into prior to the 150th
day following the Termination Date, Eastern States shall pay all amounts
deposited in the account established pursuant to Section 9.03(d) hereof to the
Trust and all amounts thereafter payable to the Trust pursuant to the
Conveyances shall be paid to the Trust in accordance with the provisions of the
Conveyances and such amounts shall be distributed to Unitholders in accordance
with the provisions hereof. The Trustee may accept any offer (including offers,
if any, made by Eastern States for all or any part of the Remaining Royalty
Interests as it deems to be in the best interests of the Trust and Unitholders
(provided the Remaining Royalty Interests shall not be sold in more than _____
parts) and may continue for up to one calendar year after the Termination Date
to seek a buyer or buyers of any remaining assets and properties, free and clear
of any Eastern States purchase rights, in an orderly fashion not involving a
public auction. If any assets or property constituting the Trust Estate have not
been sold, or a definitive agreement for sale thereof has not been entered into,
by the end of one calendar year following the Termination Date, the Trustee
shall cause such property to be sold at public auction to the highest cash
bidder (which may be Eastern States or any of its Affiliates). Notice of any
such sale by auction shall be mailed at least 30 days prior to such sale to each
Unitholder at his address as it appears upon the ownership ledger of the
Trustee.
(f) The Trustee shall not be required to obtain approval of the
Unitholders prior to selling any asset or property of the Trust Estate pursuant
to this Section 9.03. Information provided to any prospective buyer of the
Royalty Interests shall include the impact, if any, of capital expenditures on
future amounts payable with respect to the Royalty Interests and the effect of
termination of the Trust on payment of operating costs under the Conveyances.
Upon making final distribution to the Unitholders and termination of the Trust
in accordance with Section 3808 of the Business Act, neither the Trustee, the
Delaware Trustee, nor any Entity serving in such capacity shall be under further
liability. Eastern States, for purposes of this Section 9.03, shall include all
of Eastern States' successors in interests and assigns, and, upon written notice
to the Trustee, Eastern States' rights under this Section 9.03 shall be fully
assignable by Eastern States to any Person and an assignment upon such
references herein to Eastern States shall constitute references to such Person.
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SECTION 9.04 Conditional Right of Repurchase.
(a) Notwithstanding any provision in this Agreement to the
contrary, Eastern States is hereby granted the right to repurchase all (but not
less than all) outstanding Units at any time that 15% or less of the then
outstanding Units are owned by Persons other than Eastern States and its
Affiliates. Any such repurchase shall be at a price equal to the greater of (i)
the highest price at which Eastern States or any of its Affiliates acquired
Units during the 90 days immediately preceding the date (the "Determination
Date") which is three NYSE trading days prior to the date on which notice of
such exercise is delivered to the Unitholders and (ii) the average closing price
of the Units on the NYSE, or if not listed for trading on the NYSE, on such
other national securities exchange or NASDAQ, in any case for the 30 trading
days immediately preceding the Determination Date (the "Average Closing Price").
If Eastern States or any of its Affiliates acquires Units from Persons other
than Eastern States or its Affiliates during the period which is three NYSE
trading days following the Determination Date at a price per Unit greater than
that at which Eastern States or any of its Affiliates acquired Units during the
90 days immediately preceding the Determination Date, then for purposes of
clause (i) of this Section 9.04(a) the highest price shall be such greater
price.
(b) If Eastern States elects to repurchase all Units pursuant to
Section 9.04(a) of this Agreement, Eastern States and the Trustee shall, prior
to the fixed date for purchase, give all Unitholders of record not less than 15
days nor more than 60 days written notice pursuant to Section 12.08 of this
Agreement specifying the time and place of such repurchase, calling upon each
such Unitholder to surrender to Eastern States on the repurchase date at the
place designated in such notice its Certificate or Certificates representing the
number of Units specified in such notice of repurchase. On or after the
repurchase date, each holder of Units to be repurchased shall present and
surrender its Certificates for such Units to Eastern States at the place
designated in such notice and thereupon the purchase price of such Units shall
be paid to or on the order of the Person whose name appears on such Certificate
or Certificates as the owner thereof. In no event may fewer than all of the
outstanding Units represented by the Certificates be repurchased (except with
respect to any such Units held by Eastern States or any of its Affiliates).
(c) If a notice of repurchase has been given by Eastern States
and the Trustee pursuant to Section 9.04(b) of this Agreement and if, on or
before the date fixed for repurchase, the funds necessary for such repurchase
shall have been set aside by Eastern States, separate and apart from its other
funds, in trust for the pro rata benefit of the holders of the Units so noticed
for repurchase then, notwithstanding that any Certificate or Certificates for
such Units have not been surrendered, at the close of business on the repurchase
date the holders of such Units shall cease to be Unitholders and shall have no
interest in or claims against Eastern States, the Trust, the Delaware Trustee or
the Trustee by virtue thereof and shall have no voting or other rights with
respect to such Units, except the right to receive the purchase price payable
upon such repurchase (which purchase price shall not include any sums for
Quarterly Distribution Amounts made or to be made to Unitholders on Quarterly
Record Dates occurring after the date of written notice of such repurchase),
without interest thereon, upon surrender (and endorsement, if required by
Eastern States) of their Certificates, and the Units evidenced thereby shall no
longer be held of record in the names of such
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Unitholders. Subject to applicable escheat laws, any monies so set aside by
Eastern States and unclaimed at the end of two years from the repurchase date
shall revert to the general funds of Eastern States, after which reversion the
holders of such Units so noticed for repurchase shall look only to the general
funds of Eastern States for the payment of the purchase price. Any interest
accrued on funds so deposited shall be paid to Eastern States from time to time
as requested by Eastern States.
(d) If Eastern States exercises and consummates its right of
repurchase granted pursuant to this Section 9.04, then at the option of Eastern
States it may cause the Trust to be terminated by providing written notice
thereof to the Trustee and the Delaware Trustee. Subject to the rights of the
Unitholders with respect to distributions, within 30 days following written
notice of Eastern States' election to terminate the Trust pursuant to this
Section 9.04(d), the Trustee shall, subject to a reasonable reserve determined
by the Trustee to be necessary in connection with the winding up of the Trust,
cause all Remaining Royalty Interests (and all proceeds of production
attributable to the Remaining Royalty Interests) and any other assets of the
Trust to be conveyed to Eastern States or its assignee.
(e) Eastern States, for purposes of this Section 9.04, shall
include all of Eastern States' successors in interest and Affiliates and, upon
written notice to the Trustee, Eastern States' rights under this Section 9.04
shall be fully assignable by Eastern States to any of its Affiliates or to any
Person to whom it sells or transfers all or substantially all of the Underlying
Properties, and, from and after any such assignment, references in this Section
9.04 to Eastern States shall constitute references to such assignee.
SECTION 9.05 Reorganization or Business Combination.
(a) The Trust may convert into or merge or consolidate with or
into one or more limited partnerships, general partnerships, corporations,
business trusts, limited liability companies, or associations, or unincorporated
businesses if such transaction (i) is agreed to by the Trustee and by the
affirmative vote of Unitholders owning more than 66 2/3% of the then outstanding
Units at a meeting duly called and held in accordance with Article VIII, and
(ii) is permitted under the Business Act and any other applicable law.
(b) Upon the effective date of a certificate of merger duly
filed in accordance with the Business Act the following shall be deemed to
occur, in addition to such effects as may be specified under the Business Act as
then in effect:
(i) all of the rights, privileges and powers of each
of the business entities that has merged or consolidated, and all
property, real, personal and mixed, and all debts due to any of those
business entities and all other things and causes of action belonging
to each of those business entities shall be vested in the surviving
business entity and, after the merger or consolidation, shall be the
property of the surviving business entity to the extent they were part
of each constituent business entity;
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(ii) the title to any real property vested by deed or
otherwise in any of those constituent business entities shall not
revert and shall not be in any way impaired because of the merger or
consolidation;
(iii) all rights of creditors and all liens on or
security interest in property of any of those constituent business
entities shall be preserved unimpaired;
(iv) all debts, liabilities and duties of those
constituent business entities shall attach to the surviving business
entity, and may be enforced against it to the same extent as if the
debts, liabilities and duties had been incurred or contracted by it;
and
(v) if the Trust is the surviving or resulting
entity, the governing instrument of the Trust shall be amended or a new
governing instrument adopted as set forth in the certificate of merger.
(c) A merger or consolidation effected pursuant to this Section
9.05 shall not be deemed to result in a transfer or assignment of assets or
liabilities from one entity to another having occurred.
(d) The Trust may convert into another entity in accordance with
Section 3821 of the Business Act.
ARTICLE X
AMENDMENTS
SECTION 10.01 Prohibited Amendments.
No amendment may be made to any provision of this Agreement that would:
(a) alter the purpose of the Trust or permit the Trustee or the
Delaware Trustee to engage in any business activities or authority activity
substantially different from that specified herein;
(b) alter the rights of the Unitholders vis-a-vis each other; or
(c) permit the Trustee or the Delaware Trustee to distribute the
Royalty Interests in kind either during the continuation of the Trust or during
the period of liquidation or winding up under Section 9.03.
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SECTION 10.02 Permitted Amendments.
The Delaware Trustee, the Trustee and Eastern States may, jointly, from
time to time supplement or amend this Agreement without the approval of
Unitholders, in order to cure any ambiguity, to correct or supplement any
provision contained herein which may be defective or inconsistent with any other
provisions herein, or to change the name of the Trust, provided that such
supplement or amendment does not adversely affect the interests of the
Unitholders, and provided, further, that any amendment to this Agreement made to
change the name of the Trust in accordance with Section 11.04 hereof or
otherwise shall be conclusively deemed not to adversely affect the interests of
the Unitholders. All other permitted amendments to the provisions of this
Agreement may be made only by a vote of the Unitholders represented at a meeting
held in accordance with the requirements of Article VIII. No amendment that
increases the obligations, duties or liabilities or affects the rights of the
Delaware Trustee or the Trustee or any Entity serving in any such capacity shall
be effective without the express written approval of such trustee or Entity.
Prior to the execution of any amendment to this Agreement, the Trustee
and the Delaware Trustee shall be entitled to receive and rely upon an opinion
of counsel stating that the execution of such amendment is authorized or
permitted by this Agreement.
ARTICLE XI
ARBITRATION
TO THE FULLEST EXTENT PERMITTED BY LAW, THE PARTIES TO THIS AGREEMENT
AGREE THAT ANY DISPUTE, CONTROVERSY OR CLAIM THAT MAY ARISE BETWEEN OR AMONG
EASTERN STATES (ON THE ONE HAND) AND THE TRUST, THE TRUSTEE OR THE DELAWARE
TRUSTEE (ON THE OTHER HAND) IN CONNECTION WITH OR OTHERWISE RELATING TO THIS
AGREEMENT OR THE CONVEYANCES OR THE APPLICATION, IMPLEMENTATION, VALIDITY OR
BREACH OF THIS AGREEMENT OR THE CONVEYANCES OR ANY PROVISION OF THIS AGREEMENT
OR THE CONVEYANCES (INCLUDING, WITHOUT LIMITATION, CLAIMS BASED ON CONTRACT,
TORT OR STATUTE), SHALL BE FINALLY, CONCLUSIVELY AND EXCLUSIVELY SETTLED BY
BINDING ARBITRATION IN [FORT WORTH, TEXAS] IN ACCORDANCE WITH THE COMMERCIAL
ARBITRATION RULES (THE "RULES") OF THE AMERICAN ARBITRATION ASSOCIATION OR ANY
SUCCESSOR THERETO ("AAA") THEN IN EFFECT. TO THE FULLEST EXTENT PERMITTED BY
LAW, THE PARTIES TO THIS AGREEMENT (AND ON BEHALF OF THE TRUST) HEREBY EXPRESSLY
WAIVE THEIR RIGHT TO SEEK REMEDIES IN COURT, INCLUDING, WITHOUT LIMITATION, THE
RIGHT TO TRIAL BY JURY, WITH RESPECT TO ANY MATTER SUBJECT TO ARBITRATION
PURSUANT TO THIS ARTICLE XI. ANY PARTY TO THIS AGREEMENT MAY BRING AN ACTION,
INCLUDING, WITHOUT LIMITATION, A SUMMARY OR EXPEDITED PROCEEDING, IN ANY COURT
HAVING JURISDICTION, TO COMPEL ARBITRATION OF ANY DISPUTE, CONTROVERSY OR CLAIM
TO WHICH THIS ARTICLE XI APPLIES.
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EXCEPT WITH RESPECT TO THE FOLLOWING PROVISIONS (THE "SPECIAL PROVISIONS") WHICH
SHALL APPLY WITH RESPECT TO ANY ARBITRATION PURSUANT TO THIS ARTICLE XI, THE
INITIATION AND CONDUCT OF ARBITRATION SHALL BE AS SET FORTH IN THE RULES, WHICH
RULES ARE INCORPORATED IN THIS AGREEMENT BY REFERENCE WITH THE SAME EFFECT AS IF
THEY WERE SET FORTH IN THIS AGREEMENT.
(a) In the event of any inconsistency between the Rules and
the Special Provisions, the Special Provisions shall control. References in the
Rules to a sole arbitrator shall be deemed to refer to the tribunal of
arbitrators provided for under subparagraph (c) below in this Article XI.
(b) The arbitration shall be administered by AAA.
(c) The arbitration shall be conducted by a tribunal of three
arbitrators. Within 10 days after arbitration is initiated pursuant to the
Rules, the initiating party or parties (the "Claimant") shall send written
notice to the other party or parties (the "Respondent"), with a copy to the
Dallas office of AAA, designating the first arbitrator (who shall not be a
representative or agent of any party but may or may not be an AAA panel member
and, in any case, shall be reasonably believed by the Claimant to possess the
requisite experience, education and expertise in respect of the matters to which
the claim relates to enable such person to completely perform arbitral duties).
Within 10 days after receipt of such notice, the Respondent shall send written
notice to the Claimant, with a copy to the Dallas office of AAA and to the first
arbitrator, designating the second arbitrator (who shall not be a representative
or agent of any party, but may or may not be an AAA panel member and, in any
case, shall be reasonably believed by the Respondent to possess the requisite
experience, education and expertise in respect of the matters to which the claim
relates to enable such person to competently perform arbitral duties). Within 10
days after such notice from the Respondent is received by the Claimant, the
Respondent and the Claimant shall cause their respective designated arbitrators
to select any mutually agreeable AAA panel member as the third arbitrator. If
the respective designated arbitrators of the Respondent and the Claimant cannot
so agree within said 10 day period, then the third arbitrator will be determined
pursuant to the Rules. For purposes of this Article XI, Eastern States (on the
one hand) and the Trust, the Trustee and the Delaware Trustee (on the other
hand) shall each be entitled to the selection of one arbitrator. Prior to
commencement of the arbitration proceeding, each arbitrator shall have provided
the parties with a resume outlining such arbitrator's background and
qualifications and shall certify that such arbitrator is not a representative or
agent of any of the parties. If any arbitrator shall die, fail to act, resign,
become disqualified or otherwise cease to act, then the arbitration proceeding
shall be delayed for 15 days and the party by or on behalf of whom such
arbitrator was appointed shall be entitled to appoint a substitute arbitrator
(meeting the qualifications set forth in this Article XI) within such 15 day
period; provided, however, that if the party by or on behalf of whom such
arbitrator was appointed shall fail to appoint a substitute arbitrator within
such 15 day period, the substitute arbitrator shall be a neutral arbitrator
appointed by the AAA arbitrator within 15 days thereafter.
40
<PAGE> 46
(d) All arbitration hearings shall be commenced within 120
days after arbitration is initiated pursuant to the Rules, unless, upon a
showing of good cause by a party to the arbitration, the tribunal of arbitrators
permits the extension of the commencement of such hearing; provided, however,
that any such extension shall not be longer than 60 days.
(e) All claims presented for arbitration shall be particularly
identified and the parties to the arbitration shall each prepare a statement of
their position with recommended courses of action. These statements of position
and recommended courses of action shall be submitted to the tribunal of
arbitrators chosen as provided hereinabove for binding decision. The tribunal of
arbitrators shall not be empowered to make decisions beyond the scope of the
position papers.
(f) The arbitration proceeding will be governed by the
substantive laws of the State of Delaware (as provided in Section 12.06) and
will be conducted in accordance with such procedures as shall be fixed for such
purpose by the tribunal of arbitrators, except that (i) discovery in connection
with any arbitration proceeding shall be conducted in accordance with the
Federal Rules of Civil Procedure and applicable case law, (ii) the tribunal of
arbitrators shall have the power to compel discovery and (iii) unless the
parties otherwise agree and except as may be provided in this Article XI, the
arbitration shall be governed by the United States Arbitration Act, 9 U.S.C.
ss.ss. 1-16, to the exclusion of any provision of state law or other applicable
law or procedure inconsistent therewith or which would produce a different
result. The parties shall preserve their right to assert and to avail themselves
of the attorney-client and attorney-work product privileges, and any other
privileges to, which they may be entitled pursuant to applicable law. No party
to the arbitration or any arbitrator may compel or require mediation and/or
settlement conferences without the prior written consent of all such parties and
the tribunal of arbitrators.
(g) The tribunal of arbitrators shall make an arbitration
award as soon as possible after the later of the close of evidence or the
submission of final briefs, and in all cases the award shall be made not later
than 30 days following submission of the matter. The finding and decision of a
majority of the arbitrators shall be final and shall be binding upon the
parties. Judgment upon the arbitration award or decision may be entered in any
court having jurisdiction thereof or application may be made to any such court
for a judicial acceptance of the award and an order of enforcement, as the case
may be. The tribunal of arbitrators shall have the authority to assess liability
for pre-award and post-award interest on the claims, attorneys' fees, expert
witness fees and all other expenses of arbitration as such arbitrators shall
deem appropriate based on the outcome of the claims arbitrated. Unless otherwise
agreed by the parties to the arbitration in writing, the arbitration award shall
include findings of fact and conclusions of law.
(h) Nothing in this Article XI shall be deemed to (i) limit
the applicability of any otherwise applicable statute of limitations or repose
or any waivers contained in this Agreement, (ii) constitute a waiver by any
party hereto of the protections afforded by 12 U.S.C. ss. 91 or any successor
statute thereto or any substantially equivalent state law, or (iii) restrict the
right of the Trustee to make application to any state or federal district court
having jurisdiction in Tarrant County, Texas, or Delaware (state or federal
courts) to appoint a successor Trustee or to request
41
<PAGE> 47
instructions with regard to any provision in this Agreement when the Trustee is
unsure of its obligations thereunder.
(i) To the fullest extent permitted by law, this Article XI
shall preclude participation by the Trust in any class action brought against
Eastern States by any Person who is not a Unitholder and the Trustee shall opt
out of any such class action in which the Trust is a purported class member.
ARTICLE XII
MISCELLANEOUS
SECTION 12.01 Inspection of Trustee's Books.
Each Unitholder and his duly authorized agents and attorneys shall have
the right, at his own expense and during reasonable business hours, to examine
and inspect the records (including, without limitation, the ownership ledger) of
the Trust and the Trustee in reference thereto.
SECTION 12.02 Disability of a Unitholder.
Any payment or distribution to a Unitholder may be made by check of the
Trustee drawn to the order of the Unitholder, regardless of whether or not the
Unitholder is a minor or under other legal disability, without the Trustee
having further responsibility with respect to such payment or distribution. This
Section 12.02 shall not be deemed to prevent the Trustee from making any payment
or distribution by any other method that is appropriate under law.
SECTION 12.03 Merger or Consolidation of Trustee or Delaware Trustee.
Neither a change of name of either the Trustee or the Delaware Trustee
nor any merger or consolidation of its corporate powers with another bank or
with a trust company nor the sale or transfer of all or substantially all of its
trust operations to a separate corporation shall affect its right or capacity to
act hereunder; provided, however, the Delaware Trustee or any successor thereto
shall maintain its principal place of business in the State of Delaware.
SECTION 12.04 Change in Trust Name.
Upon the request of Eastern States submitted to the Trustee and the
Delaware Trustee, the Trustee shall, without the vote or consent of any
Unitholders, take all action necessary to change the name of the Trust to a name
mutually agreeable to the Trustee and Eastern States and, upon effecting such
name change, the Delaware Trustee shall amend the Certificate of Trust on file
in the office of the Secretary of State of Delaware to reflect such name change.
42
<PAGE> 48
SECTION 12.05 Filing of this Agreement.
Neither this Agreement nor any executed copy hereof need be filed in
any county in which any of the Trust Estate is located, but the same may be
filed for record in any county by the Trustee. In order to avoid the necessity
of filing this Agreement for record, each of the Delaware Trustee and the
Trustee agrees that for the purpose of vesting the record title to the Trust
Estate in any successor trustee, the succeeded trustee shall, upon appointment
of any successor trustee, execute and deliver to such successor trustee
appropriate assignments or conveyances.
SECTION 12.06 Choice of Law.
This Agreement and the Trust shall be governed by the laws of the State
of Delaware (without regard to the conflict of laws principles thereof) in
effect at any applicable time in all matters, including the validity,
construction and administration of this Agreement and the Trust, the
enforceability of the provisions of this Agreement under Article XI, all rights
and remedies hereunder, and the services of the Delaware Trustee and Trustee
hereunder. Furthermore, except as otherwise provided in this Agreement, the
rights, powers, duties and liabilities of the Delaware Trustee and the Trustee
and the Unitholders shall be as provided under the Business Act and other
applicable laws of the State of Delaware and the United States of America in
effect at any applicable time; provided, however, that there shall not be
applicable to the Trustee, the Delaware Trustee, the Unitholders, the Trust or
this Agreement (i) the provisions of Section 3450 of Title 12 of the Delaware
Code or (ii) any provisions of the laws (statutory or common) of the State of
Delaware (other than the Business Act) pertaining to trusts which are
inconsistent with the rights, duties, powers, limitations or liabilities of the
Trustee, the Delaware Trustee, or the Unitholders set forth or referenced in
this Agreement.
SECTION 12.07 Severability.
If any provision of this Agreement or the application thereof to any
Person or circumstances shall be finally determined by a court of proper
jurisdiction to be illegal, invalid or unenforceable to any extent, the
remainder of this Agreement or the application of such provision to Persons or
circumstances other than those as to which it is held illegal, invalid or
unenforceable shall not be affected thereby, and every provision of this
Agreement shall be valid and enforced to the fullest extent permitted by law.
SECTION 12.08 Notices.
Any notice or demand which by any provision of this Agreement is
required or permitted to be given or served upon the Trustee or any Entity
serving in such capacity by any party hereto or any Unitholder may be given or
served by being deposited, postage prepaid, and by registered or certified mail,
in a post office or letter box addressed (until another address is designated by
notice to the parties hereto and the Unitholders) to the Trustee at 500
Throckmorton, Suite 801, Fort Worth, Texas 76102, Attention: Corporate Trust
Department, Appalachian Natural Gas Trust, and such notice or
43
<PAGE> 49
demand shall be deemed to be given only upon receipt thereof by the Trustee. Any
notice or demand which by any provision of this Agreement is required or
permitted to be given or served upon the Delaware Trustee or any Entity serving
in such capacity by any party hereto or any Unitholder may be given or served by
being deposited, postage prepaid, and by registered or certified mail, in a post
office or letter box addressed (until another address is designated by notice to
the parties hereto and the Unitholders) to the Delaware Trustee at Three
Christina Center, 201 North Walnut Street, Wilmington, Delaware 19801,
Attention: Corporate Trust Department, and such notice or demand shall be deemed
to be given only upon receipt thereof by the Delaware Trustee. Any notice or
other communication by the Trustee or the Delaware Trustee to any party hereto
or any Unitholder shall be deemed to have been sufficiently given, for all
purposes, when deposited, postage prepaid, in the United States mail addressed
to said holder at his last address as shown on the ownership ledger of the
Trustee or other method of notice. Any notice or demand which by any provision
of this Agreement is required or permitted to be given or served upon Eastern
States, may be given or served by being deposited, postage prepaid, and by
registered or certified mail, in a post office or letter box addressed (until
another address is designated by notice to the Trustee and Delaware Trustee) to
Eastern States Oil & Gas, Inc., 2800 Eisenhower Avenue, Alexandria, Virginia
22314, Attention: Stevens V. Gillespie and such notice shall be deemed to be
given only upon receipt thereof by Eastern States.
SECTION 12.09 Counterparts.
This Agreement may be executed in a number of counterparts, each of
which shall constitute an original, but such counterparts shall together
constitute but one and the same instrument.
SECTION 12.10 Successors.
This Agreement shall inure to the benefit of and be binding upon the
parties hereto and their respective.
44
<PAGE> 50
IN WITNESS WHEREOF, Eastern States has caused this Agreement to be
executed by a duly authorized President or Senior Vice President and attested by
a duly authorized Secretary or Assistant Secretary of Eastern States, the
Trustee has caused this Agreement to be executed by its duly authorized Senior
Vice President-Trust, and attested by its duly authorized Trust Officer, and the
Delaware Trustee has caused this Agreement to be executed by its duly authorized
Senior Trust Officer and attested by its duly authorized Secretary or Assistant
Secretary, as of the day and year first above written.
ATTEST: EASTERN STATES OIL & GAS, INC.
- ---------------------------------------- By: --------------------------------
Name: Name:
Title: Title:
ATTEST: BANK ONE, TEXAS, N.A.
- ---------------------------------------- By: --------------------------------
Name: Name:
Title: Title:
ATTEST: BANK ONE DELAWARE, INC.
- ---------------------------------------- By: --------------------------------
Name: Name:
Title: Title:
45
<PAGE> 51
ACKNOWLEDGMENT
STATE OF )
) SS:
COUNTY OF )
On the ______ day of ___________ 1999, before me personally came
____________ __________________, known to me to be ____________________ of
Eastern States Oil & Gas, Inc., the corporation that executed the foregoing
instrument, who, being duly sworn, acknowledged that he knows the seal of said
corporation; that the seal affixed to said instrument is such corporate seal;
that it was so affixed by the order of the Board of Directors of said
corporation; and that he signed his name thereto by like order.
---------------------------------
Notary Public
My commission expires:
-----------
46
<PAGE> 52
EXHIBIT A
FORM OF TRUST UNIT CERTIFICATE
[Face of Certificate]
Number Units
---
Organized Under the Laws of the State of Delaware Total Units of Beneficial
Interest Created By, Issued Under and Subject to the Amended and Restated Trust
Agreement dated as of _________, 1999 for the Appalachian Natural Gas Trust
See Reverse for Mandatory Divestiture
Provisions and Certain Definitions
CUSIP NO.
----------
Certificate for Units of Beneficial Interest in
Appalachian Natural Gas Trust
This certifies that
is the owner of
Fully Paid Units of Beneficial Interest ("Units") in that
certain Trust known and designated as the Appalachian Natural Gas Trust, created
and established under the terms of the above referenced Amended and Restated
Trust Agreement (the "Trust Agreement") between Eastern States Oil & Gas, Inc.,
a Delaware corporation ("Eastern States"), Bank One, Texas, N.A., as Trustee,
and Bank One Delaware, Inc., as Delaware Trustee, a duplicate original of which
Trust Agreement is for the information of all concerned, held by said Trustee at
its trust office in Fort Worth, Texas. Said Trust Agreement is hereby referred
to and incorporated as a part of this Certificate for all purposes, and the
owner of this Certificate by accepting same consents to, and becomes bound by,
all the terms and provisions of said Trust Agreement and the provisions herein.
The Units represented by this Certificate are transferable on the books of the
Trustee by the holder hereof in person, or by duly authorized attorney, upon
surrender of this Certificate, properly endorsed, to the Trustee. This
Certificate shall not be valid until countersigned and registered by the
Transfer Agent and Registrar.
Witness the seal of the Trustee and the signature of the duly authorized officer
of the Trustee.
[Seal of Bank One, Texas, N.A.]
A-1
<PAGE> 53
Dated:
Countersigned and Registered:
EQUISERVE BANK ONE, TEXAS, N.A.
Transfer Agent and Registrar As Trustee
By: By:
---------------------------------- --------------------------
Authorized Signature Authorized Officer
A-2
<PAGE> 54
[Reverse Side of Certificate]
Pursuant to Section 3.12 of the Trust Agreement, the Trustee may require
mandatory divestiture of a Unitholder's Trust Units in the Trust in the event
that the Trust or the Trustee is named in certain proceedings which seek the
cancellation or forfeiture of any property in which the Trust has an interest
because of the nationality or other status of such Unitholder. See Section 3.12
of the Trust Agreement for complete details.
The following abbreviations, when used in the inscription on the face of this
certificate, shall be construed as though they were written out in full
according to applicable laws or regulations:
TEN COM -- as tenants in common
TEN ENT -- as tenants by the entireties
JT TEN -- as joint tenants with right of survivorship and not as tenants
in common
UNIF GIFT MIN ACT -- ________. . . Custodian . . ________. . . under Uniform
(Cust) (minor)
Gifts to Minors Act . . ._______________
(State)
Additional abbreviations may also be used though not in the above list.
ASSIGNMENT
For Value Received _______________________________ hereby sell, assign and
transfer unto
(Please insert social security or other identifying number of assignee)
- --------------------------------------------------------------------------------
Please print or typewrite name and address of assignee
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
_________________ Units of Beneficial Interest represented by the within
Certificate, and do hereby constitute and appoint irrevocably ______________
Attorney to transfer the said Units on the books of the within named Trustee,
with full power of substitution in the premises.
Dated:
-----------------------------
Signature
Notice: The signature(s) to this Assignment must correspond with the Name(s) as
written upon the face of the certificate exactly, without any change whatsoever.
-----------------------------
Signature
A-3
<PAGE> 55
Signature(s) must be guaranteed by
a participant in a recognized
signature guaranty medallion
program.
The holder of this certificate has acquired an interest in the Appalachian
Natural Gas Trust. The address of the Trust is 500 Throckmorton, Suite 801, Fort
Worth, Texas 76102 and its taxpayer identification number is 75-6550504.
The Trust's tax shelter registration number is __________. The holder must
report this registration number to the Internal Revenue Service if the holder
claims any deduction, loss, credit or other tax benefit or reports any income by
reason of his investment in the Trust. The holder must report this registration
number (as well as the name and taxpayer identification number of the Trust) on
Form 8271. FORM 8271 MUST BE ATTACHED TO THE RETURN ON WHICH YOU CLAIM THE
DEDUCTION, LOSS, CREDIT OR OTHER TAX BENEFIT OR REPORT ANY INCOME.
ISSUANCE OF A REGISTRATION NUMBER DOES NOT INDICATE THAT THIS INVESTMENT OR THE
CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE INTERNAL
REVENUE SERVICE.
If the holder of this certificate transfers an interest in the Trust to another
person, he is required by the Internal Revenue Service to keep a list containing
that person's name, address, taxpayer identification number, the date on which
he transferred the interest and in the name, address, and tax shelter
registration number of the Trust. If the holder of this certificate does not
wish to keep such a list, the holder must (i) send the information specified
above to the Trustee at the above address, which will keep the list on behalf of
the holder and (ii) give a copy of this notice to the person to whom his
interest was transferred.
A-4
<PAGE> 1
Exhibit 5.1
[Richards, Layton & Fingers, P.A. Letterhead]
October 14, 1999
Appalachian Natural Gas Trust
c/o Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue
Alexandria, Virginia 22314
Re: Appalachian Natural Gas Trust
Ladies and Gentlemen:
We have acted as special Delaware counsel for Eastern States Oil & Gas,
Inc., a Delaware corporation (the "Company"), and Appalachian Natural Gas Trust,
a Delaware business trust (the "Trust"), in connection with the matters set
forth herein. At your request, this opinion is being furnished to you.
For purposes of giving the opinions hereinafter set forth, our examination
of documents has been limited to the examination of originals or copies of the
following:
(a) The Certificate of Trust of the Trust, as filed with the Secretary of
State on August 19, 1999, as amended by the Certificate of Amendment to
Certificate of Trust, as filed with the Secretary of State on October 8, 1999;
(b) The Trust Agreement of the Trust, dated as of August 18, 1999, as
amended by the Restated Trust Agreement, dated as of October 4, 1999, among the
Company and the trustees of the Trust named therein;
(c) The Registration Statement (the "Registration Statement") on Form S-1,
including a preliminary prospectus with respect to the Trust (the "Prospectus"),
relating to the
<PAGE> 2
Appalachian Natural Gas Trust
October 14, 1999
Page 2
Trust Units representing beneficial interests in the assets of the Trust (each,
a "Trust Unit" and collectively, the "Trust Unit"), as filed by the Company and
the Trust with the Securities and Exchange Commission on August 26, 1999;
(d) A form of Amended and Restated Trust Agreement for the Trust, to be
entered into between the Company, the trustees of the Trust named therein, and
the holders, from time to time, of the Trust Units (the "Trust Agreement"), to
be attached as an exhibit to the Registration Statement
(e) A form of certificate evidencing the Trust Units (the "Certificate");
and
(f) A Certificate of Good Standing for the Trust, dated October 14, 1999,
obtained from the Secretary of State.
With respect to all documents examined by us, we have assumed (i) the
authenticity of all documents submitted to us as authentic originals, (ii) the
conformity with the originals of all documents submitted to us as copies or
forms, and (iii) the genuineness of all signatures.
For purposes of this opinion, we have assumed (i) that the Trust Agreement
and the Certificate of Trust are in full force and effect and have not been
amended, (ii) except to the extent provided in paragraph 1 below, the due
organization or due formation, as the case may be, and valid existence in good
standing of each party to the documents examined by us under the laws of the
jurisdiction governing its creation, organization or formation, (iii) the legal
capacity of natural persons who are parties to the documents examined by us,
(iv) that each of the parties to the documents examined by us has the power and
authority to execute and deliver, and to perform its obligations under, such
documents, (v) the due authorization, execution and delivery by all parties
thereto of all documents examined by us, (vi) the receipt by each Person to whom
a Trust Unit is to be issued by the Trust (collectively, the "Trust Unit
Holders") of a Certificate for such Trust Unit and the payment for such Trust
Unit, in accordance with the Trust Agreement and the Prospectus, and (vii) that
the Trust Units are issued and sold to the Trust Unit Holders in accordance with
the Trust Agreement and the Prospectus. We have not participated in the
preparation of the Registration Statement and assume no responsibility for its
contents.
This opinion is limited to the laws of the State of Delaware, and we have
not considered and express no opinion on the laws of any other jurisdiction,
including federal laws and rules and regulations relating thereto. Our opinions
are rendered only with respect to Delaware laws and rules, regulations and
orders thereunder which are currently in effect.
Based upon the foregoing, and upon our examination of such questions of law
and statutes of the State of Delaware as we have considered necessary or
appropriate, and
<PAGE> 3
Appalachian Natural Gas Trust
October 14, 1999
Page 3
subject to the assumptions, qualifications, limitations and exceptions set forth
herein, we are of the opinion that:
1. The Trust has been duly created and is validly existing in good standing
as a business trust under the Delaware Business Trust Act.
2. The Trust Units of the Trust will represent valid and, subject to the
qualifications set forth in paragraph 3 below, fully paid and nonassessable
undivided beneficial interests in the assets of the Trust.
3. The Trust Unit Holders, as beneficial owners of the Trust, will be
entitled to the same limitation of personal liability extended to stockholders
of private corporations for profit organized under the General Corporation Law
of the State of Delaware. We note that the Trust Unit Holders may be obligated
to make payments as set forth in the Trust Agreement.
We consent to the filing of this opinion with the Securities and Exchange
Commission as an exhibit to the Registration Statement. We hereby consent to the
use of our name under the heading "Validity of the Trust Units" in the
Prospectus. In giving the foregoing consents, we do not thereby admit that we
come within the category of persons whose consent is required under Section 7 of
the Securities Act of 1933, as amended, or the rules and regulations of the
Securities and Exchange Commission thereunder.
Very truly yours,
/s/ Richards, Layton & Fingers, P.A.
<PAGE> 1
EXHIBIT 8.1
FORM OF OPINION
OF
ANDREWS & KURTH L.L.P.
__________, 1999
Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue
Alexandria, Virginia 22314
Ladies and Gentlemen:
We have acted as special tax counsel to Eastern States Oil & Gas,
Inc., a Delaware corporation (the "Company"), in connection with the formation
of the Appalachian Natural Gas Trust, a business trust formed under the laws of
the State of Delaware ("Trust") and the proposed sale of Units by the Company as
described in the Registration Statement on Form S-1/S-1 (Registration No.
333-85955) and the prospectus included as part of such Registration Statement
(the "Prospectus"), filed with the Securities and Exchange Commission on August
26, 1999, as amended October __, 1999. In connection with such representation,
we have reviewed the following documents: (i) the Restated Trust Agreement of
Appalachian Natural Gas Trust dated as of October 4, 1999, (ii) the form of
Amended and Restated Trust Agreement of Appalachian Natural Gas Trust (the
"Trust Agreement"), (iii) the Net Overriding Royalty Conveyance dated as of
September 1, 1999, conveying net overriding royalty interests in Kentucky
properties from the Company to the Trust; (iv) the Net Overriding Royalty
Conveyance dated as of September 1, 1999, conveying net overriding royalty
interests in West Virginia properties from the Company to the Trust; and (v) the
Prospectus.
We have been requested to furnish our opinion as to the material
federal income tax consequences of the formation and operation of the Trust.
Our opinion is limited to the federal income tax matters stated herein as of
the date hereof, and no opinion is implied or may be inferred beyond the
matters expressly stated herein. We express no opinion as to the impact of the
tax laws of any state on an investment in the Trust.
In rendering the following opinion we have assumed the authenticity of
all documents reviewed by us purporting to be originals, and the conformity
with the originals of documents purporting to be copies. We have assumed that
the Trust Agreement and the Conveyances, at the time of delivery, were duly
authorized, executed and delivered by the parties thereto. We have also assumed
that all representations and warranties (other than as to the subject matter
expressed herein) made by each of the parties to the Underwriting Agreement,
Trust Agreement and Conveyances were and are true, correct and complete, and
have relied upon those representations and warranties for the purposes hereof.
<PAGE> 2
Based on the foregoing, we confirm that the statements set forth under
the captions "Federal Income Tax Consequences" in the Prospectus, insofar as
such statements set forth legal conclusions and summaries of legal matters, are
accurate in all material respects, subject to the qualifications stated
therein.
Our opinion is based on the Internal Revenue Code of 1986, as amended,
the presently effective regulations thereunder, reported judicial decisions and
published revenue rulings and other administrative interpretations as of the
date hereof. It may be modified as a result of subsequent legislation,
regulations or other administrative or court interpretations, any of which
could be retroactive in effect. Our opinion is not binding on the Internal
Revenue Service ("IRS") or the courts, and no assurance can be given that the
IRS will not challenge the tax treatment described in the Prospectus or that,
if it does, that challenge would not be successful.
We hereby consent to the use of our name in the Registration Statement
and under the caption "Federal Income Tax Consequences" in the Prospectus and
consent to the filing of this opinion as an Exhibit to the Registration
Statement.
Very truly yours,
<PAGE> 1
EXHIBIT 8.2
FORM OF OPINION
OF
GOODWIN & GOODWIN, LLP
, 1999
Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue
Alexandria, Virginia 22314
Ladies and Gentlemen:
We have acted as special West Virginia counsel to Eastern States Oil &
Gas, Inc., a Delaware corporation (the "Company"), in connection with the
formation of the Appalachian Natural Gas Trust, a business trust formed under
the laws of the State of Delaware ("Trust") and the proposed sale of Units by
the Company as described in the Registration Statement on Form S-1/S-1
(Registration No. 333-85955) and the prospectus included as part of such
Registration Statement (the "Prospectus"), filed with the Securities and
Exchange Commission on August 26, 1999, as amended October , 1999. In
connection with such representation, we have reviewed the following documents:
(i) the Restated Trust Agreement of Appalachian Natural Gas Trust (the "Trust
Agreement") dated as of October 4, 1999, (ii) the Net Overriding Royalty
Conveyance dated as of October 1, 1999, conveying net overriding royalty
interests in West Virginia properties from the Company to the Trust; and
(iii) the Prospectus.
We have been requested to furnish our opinion as to the material West
Virginia state income tax consequences of the formation and operation of the
Trust. Our opinion is limited to the West Virginia income tax matters stated
herein as of the date hereof, and no opinion is implied or may be inferred
beyond the matters expressly stated herein. We express no opinion as to the
impact of federal income tax matters or the tax laws of any state on an
investment in the Trust.
In rendering the following opinion we have assumed the authenticity of
all documents reviewed by us purporting to be originals, and the conformity with
the originals of documents purporting to be copies. We have assumed that the
Trust Agreement and the Conveyance, at the time of delivery, were duly
authorized, executed and delivered by the parties thereto. We have also assumed
<PAGE> 2
[INSERT DATE]
Page 2
that all representations and warranties in the Prospectus (other than as to the
subject matter expressed herein) and made by each of the parties to the Trust
Agreement and Conveyance were and are true, correct and complete, and have
relied upon said representations and warranties for the purposes hereof.
Based on the foregoing, we confirm that the statements relating to
West Virginia law set forth under the caption "State Tax Considerations" in the
Prospectus, insofar as such statements set forth legal conclusions and
summaries of legal matters, are accurate in all material respects, subject to
the qualifications stated therein.
Our opinion is based on the laws of the State of West Virginia. It may
be modified as a result of subsequent legislation, regulations or other
administrative or court interpretations, any of which could be retroactive in
effect. Our opinion is not binding on the West Virginia State Department of Tax
and Revenue or the courts, and no assurance can be given that the West Virginia
State Department of Tax and Revenue will not challenge the tax treatment
described in the Prospectus or that, if it does, such challenge would not be
successful.
We hereby consent to the use of our name in the Registration Statement
and under the caption "State Tax Considerations" in the Prospectus and consent
to the filing of this opinion as an Exhibit to the Registration Statement.
Very truly yours,
Goodwin & Goodwin, LLP
<PAGE> 1
EXHIBIT 8.3
FORM OF OPINION
OF
VORYS, SATER, SEYMOUR AND PEASE LLP
(614) 464-6400
, 1999
[DRAFT]
Eastern States Oil and Gas
2800 Eisenhower Avenue
Alexandria, VA 22314
Re: Appalachian Natural Gas Trust
Ladies and Gentlemen:
We have acted as special Kentucky counsel to Eastern States
Oil & Gas, Inc. ("Eastern"), in connection with the formation of the
Appalachian Natural Gas Trust (the "Trust") and certain proposed conveyances
from Eastern to the Trust. Capitalized terms used in this opinion but not
expressly defined herein have the respective meanings given to them in the Form
S-1 Registration Statement (File No. 333-89555) for the Trust, as amended (the
"Registration Statement"). This opinion is given at the request of Eastern in
connection with the formation of the Trust.
In connection with this opinion, we have examined drafts of
the form of items (i) through (iii), and have relied upon the accuracy of,
without independent verification or investigation, the following:
(i) the Registration Statement;
(ii) the Kentucky Net Overriding Royalty Conveyance
("Kentucky Conveyance") in connection with the transfer of a net overriding
royalty interest (the "Net Overriding Royalty Interest") from Eastern to the
Trust;
(iii) the Amended and Restated Trust Agreement of
Appalachian Natural Gas Trust ("Trust Agreement"); and
(iv) the certificates, copies of which are attached
hereto, of the Secretary of State of the Commonwealth of Kentucky, with
respect to the qualification of Eastern and the Trust to do business in said
Commonwealth as a foreign corporation and a foreign business trust,
respectively (the "Foreign Qualification Certificates").
<PAGE> 2
October __, 1999
Page 2
The documents referenced in clauses (i) through (iii) of this paragraph are
sometimes referred to herein as the "Transaction Documents."
In such examinations, we have assumed (i) the genuineness of
all signatures, the conformity to original documents of all documents submitted
to us as copies and the authenticity of such originals of such latter
documents; (ii) the due completion, execution, and acknowledgment as indicated
thereon, and delivery of all documents and instruments and of the consideration
recited therein; (iii) the due recording of the Kentucky Conveyance in each of
the offices described on Exhibit 1 hereto; (iv) that each of the parties to the
Transaction Documents has the full power, authority and legal right under its
charter and other governing documents, internal resolutions, and applicable
laws and regulations to execute and perform its obligations under all documents
executed by it in connection with the transactions which are the subject of the
Transaction Documents; (v) that when duly authorized, executed and delivered,
each of the Transaction Documents will constitute the legal, valid and binding
obligation of Eastern and the Trust, enforceable against Eastern and the Trust
in accordance with its terms; (vi) that each of the Transaction Documents is
supported by adequate consideration, in each case consistent with and
sufficient for the purpose of the particular Transaction Document; (vii) that
each signature on any document to be recorded in the Commonwealth of Kentucky
will be acknowledged before a notary public; (viii) that any document to be
recorded in the Commonwealth of Kentucky will contain the name, address and
signature of the preparer; and (ix) that the laws of any jurisdiction other
than the Commonwealth of Kentucky which may govern any one or more of the
Transaction Documents are not inconsistent with the laws of such Commonwealth
in any matter material to this opinion.
Whenever our opinion with respect to the existence or absence
of facts is indicated to be based on our knowledge, we are referring to the
actual knowledge of the Vorys, Sater, Seymour and Pease LLP attorneys who have
represented Eastern in connection with the transactions contemplated by the
Transaction Documents. We have relied solely upon the examinations and
inquiries recited herein and, except for the examinations and inquiries recited
herein, we have not undertaken any independent investigation to determine the
existence or absence of any facts, and no inference as to our knowledge
concerning such facts should be drawn. Without limiting the generality of the
foregoing, we have made no examination of the character, organization,
activities or authority of Eastern which might have any effect upon our
opinions expressed herein and we have neither examined, nor do we opine upon,
any provision or matter to the extent that the examination or opinion would
require a financial, mathematical or accounting calculation or determination.
<PAGE> 3
October ___, 1999
Page 3
Based upon and subject to the foregoing and further
qualifications and limitations set forth below, as of the date hereof (or as of
the date of any assumption made herein or any certificate, schedule, exhibit or
inquiry stated to have been examined, made, or otherwise relied upon by us), we
are of the opinion that:
1. The income from the Net Overriding Royalty Interests
received by the Trust will not be subject to taxation (including any
requirements to withhold taxes in respect of the Trust or any holder of Trust
Units) at the Trust level by the Commonwealth of Kentucky.
2. A holder of Trust Units who is a Kentucky resident
will be required to report to the Commonwealth of Kentucky as income such Trust
Unit holder's proportionate share of income derived from the Trust Units.
3. A holder of Trust Units who is a nonresident of
Kentucky will be subject to Kentucky income tax on income from the Net
Overriding Royalty Interests allocable to Kentucky. In that regard, income
derived from the Net Overriding Royalty Interests encumbering properties in
Kentucky will be considered income derived from Kentucky sources for this
purpose. Such nonresident holder will be allowed certain deductions and
exemptions which are apportioned to Kentucky based upon the ratio of Kentucky
income to total income.
4. The distributions to be received by a holder of the
Trust Units will not be subject to withholding for Kentucky income taxes.
The opinions expressed above are subject to the following
qualifications:
All of our opinions are subject to the limitations, if any, of
Title 11 U.S.C., as amended, and of the applicable insolvency, reorganization,
moratorium or other laws affecting the enforcement of creditors' rights
generally and by principles of equity. In addition, certain remedial and other
provisions of the Transaction Documents may be limited by (i) implied
covenants of good faith, fair dealing and commercially reasonable conduct, (ii)
judicial discretion, in the instance of multiple or equitable remedies, and
(iii) by the public policies and laws of Kentucky.
We express no opinion as to (a) title or ownership of
property; (b) the priority of any lien, security interest or other encumbrance;
or (c) the creation, attachment or perfection of any lien, security interest or
other encumbrance.
<PAGE> 4
October ___, 1999
Page 4
We have not conducted requisite factual or legal examinations,
and accordingly we express no opinion, except as expressly set forth above,
with respect to the application, if any, of laws concerning or promulgated by
(a) environmental effects or agencies; (b) banks and thrift institutions,
insurance or utilities; (c) fraudulent dispositions or obligations; (d)
securities laws; (e) restrictions attendant to financings of property by public
authorities, for example, industrial revenue bond financings; (f) racketeer
influenced and corrupt organizations (RICO) statutes; (g) political
subdivisions of the Commonwealth of Kentucky; (h) any order of any court or
other authority directed specifically to any party to the Transaction Documents
of which we do not have knowledge; (i) any taxes or tax effects, or (j) the
effect if the Kentucky Conveyance was not recorded.
In addition, we express no opinion as to the enforceability of
rights, provisions or interests to the extent, if any, dependent upon the
enforceability of the following terms or provisions, if any, contained in any
of the Transaction Documents (a) waivers of rights of debtors or others which
may not be waived or which may be waived only under certain circumstances under
applicable law; (b) provisions of the Transaction Documents to the extent held
to (i) require the payment of interest on interest; (ii) compensate any party
for loss or expense in excess of actual loss or reasonable expenses or
constitute a penalty; (iii) require reimbursement for or indemnity against
actions by any person taken in violation of applicable law or public policy;
(iv) require indemnity or reimbursement by a person for additional costs or
expenses where the party reimbursed has incurred such expense by reason in part
of the effect or activities with others not party to the Transaction Documents
and has assigned or allocated the burden of reimbursement unreasonably or
arbitrarily; (v) purport to waive or negate in favor of any person the effect
of notice of a default or event of default, if any, which such person may have
at the time of closing; or (vi) include an acceleration clause and a prepayment
penalty or premium exercised with respect to the same obligation; (c) any
provision for the award of attorneys' fees to an opposing party; (d) provisions
which purport to create self-help rights or remedies not conducted under the
supervision of a court of competent jurisdiction; (e) provisions which purport
to effect the alteration or termination of rights currently held by third
parties; (f) provisions which purport to establish evidentiary standards; (g)
disclaimers of liability, or liability limitations, with respect to third
parties; (h) releases of legal or equitable rights; (i) provisions which
purport to authorize execution of various documents on behalf of another; (j)
provisions which purport to authorize sale of property without notice or
compliance with other applicable requirements under the law of the commonwealth
of Kentucky; or (k) provisions, if any, that are held to be ambiguous or
inconsistent within a Transaction Document or among the Transaction Documents.
<PAGE> 5
October ___, 1999
Page 5
The opinions expressed herein are limited to the laws of the
Commonwealth of Kentucky having effect on the date hereof and are given
respectively by those attorneys in our firm who are admitted to practice in the
Commonwealth of Kentucky. We express no opinion as to the laws of the United
States of America or any other jurisdiction. The opinions expressed herein are
furnished specifically in connection with the formation of the Trust for the
benefit of Eastern and may not be relied upon, assigned, quoted or otherwise
used in any manner or for any purpose by any other person or entity, without
our specific prior written consent. We hereby consent to the use of our name
in the Registration Statement with respect to this opinion and under the
caption "State Tax Considerations" in the Prospectus and consent to the filing
of this opinion as an Exhibit to the Registration Statement.
Very truly yours,
[VORYS, SATER, SEYMOUR AND PEASE LLP]
<PAGE> 1
EXHIBIT 10.1
DRAFT
October 12, 1999
FORM OF
NET OVERRIDING ROYALTY CONVEYANCE
APPALACHIAN NATURAL GAS TRUST
STATE OF )
----------- )
) KNOW ALL MEN BY THESE PRESENTS:
COUNTIES OF )
--------
THAT EASTERN STATES OIL & GAS, INC., a Delaware corporation
("Assignor"), for and in consideration of the sum of Ten Dollars ($10.00) and
other good and valuable consideration to Assignor paid by Bank One Texas, N.A.,
a bank organized under the laws of the United States, acting not in its
individual corporate capacity but solely as trustee under that certain Trust
Indenture establishing the Appalachian Natural Gas Trust dated as of September
1, 1999, ("Assignee"), the receipt and sufficiency of which are hereby
acknowledged, has bargained, sold, granted, conveyed, transferred, assigned, set
over and delivered, and by these presents does bargain, sell, grant convey,
transfer, assign, set over and deliver unto Assignee a net overriding royalty
interest (the "Royalty Interest") in and to the Subject Hydrocarbons in and
under, and if, as and when produced, saved and sold from, the Subject Lands
during the term of the Subject Interests equal to the Net Proceeds attributable
to the Subject Interests, as each of the above capitalized words is defined in
Article I hereof and all as more fully provided herein.
TO HAVE AND TO HOLD the Royalty Interest, together with all and
singular the rights and appurtenances thereto in anywise belonging, unto
Assignee, its successors and assigns, subject, however, to the terms and
provisions of this Conveyance; and Assignor does by these presents bind and
obligate itself its successors and assigns, to WARRANT and FOREVER defend all
and singular the Royalty Interest unto the said Assignee, its successors and
assigns, against every person whomsoever lawfully claiming or to claim the same
or any part thereof by, through or under Assignor, but not otherwise.
ARTICLE I
DEFINITIONS
As used herein, the following words, terms or phrases have the
following meanings:
"Accounting Procedure" means the Accounting Procedure attached hereto
as Exhibit C.
"Affiliate" means, as to the party specified, any Person controlling,
controlled by or under common control with such party, with the concept of
control in such context meaning the possession, directly or indirectly, of the
power to direct or cause the direction of the management and policies of
another, whether through the ownership of voting securities, by contract or
otherwise. The Trust shall not be deemed an Affiliate of Assignor.
<PAGE> 2
"Aggregate Gross Proceeds" means, for each Computation Period, an
amount equal to the sum of (a) 80% of Existing Well Gross Proceeds for such
Computation Period, plus (b) 10% of New Well Gross Proceeds for such Computation
Period.
"Aggregate Deductible Costs" means, for each Computation Period, an
amount equal to the sum of (a) 80% of Existing Well Deductible Costs for such
Computation Period, plus (b) 10% of New Well Deductible Costs for such
Computation Period, plus (c) Excess Aggregate Deductible Costs for the preceding
Computation Period (including any remaining Excess Aggregate Deductible Costs
carried forward from any preceding Computation Period), plus (d) interest on the
amount of Excess Aggregate Deductible Costs existing at the end of the preceding
Computation Period, calculated from the last day of the preceding Computation
Period to the last day of the Computation Period for which Aggregate Deductible
Costs are being determined, at the Prime Interest Rate in effect at the
beginning of such Computation Period.
"Assignor" means the Assignor named herein while Assignor owns all or
any part of or interest in the Subject Interests and any other Person or Persons
(excluding Assignee) who hereafter may acquire all or any part of or interest in
the Subject Interests.
"Assignee" means the Assignee named herein (and any successor Trustee
under the Trust Indenture) while it owns all or any part of or interest in the
Royalty Interest and any other Person or Persons who may acquire legal title to
all or any part of or interest in the Royalty Interest.
"Coal Bed Methane" means methane gas normally produced from coal beds
or any related, associated or adjacent rock materials, including gas produced
from previously mined areas.
"Computation Period" means (i) initially, the period commencing on the
Effective Date and ending on September 30, 1999, and (ii) each calendar quarter
thereafter.
"Conveyance" means this Net Overriding Royalty Conveyance.
"Designated Wells" means the oil and gas wells described on Exhibit A-1
attached hereto.
"Designated Excluded Wells" means the oil and gas wells described on
Exhibit B-1 attached hereto.
"Devonian Shale" means the organic-rich, gas-bearing predominately
shale and silt sequence of Upper Devonian age deposited strata in which its base
is coincident with the top of the stratigraphically older Onondaga Limestone of
the Devonian Erian series.
"Drilling Overhead Fee" shall mean the fee charged by Assignor in
accordance with Article IV of the Accounting Procedure.
"Effective Date" means 8:00 o'clock A.M., local time in effect at the
location of each Subject Interest, on September 1, 1999.
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<PAGE> 3
"Excess Aggregate Deductible Costs" means, for each Computation Period,
an amount equal to the excess, if any, of Aggregate Deductible Costs for such
Computation Period over Aggregate Gross Proceeds for such Computation Period.
"Excluded Interests" means (a) the Designated Excluded Wells, together
with each kind and character of right, title and interest which Assignor owns in
or under the lands situated within a circle around such Designated Excluded Well
having a radius of 1,000 feet and the center of which is the wellbore of such
Designated Excluded Well, whether such right, title and interest of Assignor be
a mineral leasehold interest, royalty interest, overriding interest, fee mineral
interest, fee interest, surface interest or other type of interest or estate,
(b) each geological formation or horizon underlying the Subject Lands that
contains Coal Bed Methane, (c) any interest of Assignor that is not specifically
described in the Conveyance or that is expressly excluded from the definition of
Subject Interests and/or Subject Lands, and (d) the interests of third Persons
in any of the Subject Leases or Subject Lands arising under the farmout
agreements and other similar agreements described on Exhibit B-2 attached hereto
whether such interests have been previously earned and/or assigned or such
interests are earned by, and/or assigned to, such Person in the future.
"Excluded Wells" means (a) the Designated Excluded Wells, and (b) any
other oil and gas well to the extent (i) such well is completed in and producing
from the lands and depths that are part of the Excluded Interests or (ii) the
production therefrom is otherwise attributable to the Excluded Interests.
"Existing Well Deductible Costs" means, for each Computation Period, an
amount equal to that portion of Deductible Costs for such Computation Period
attributable to the Existing Wells, the Subject Hydrocarbons produced therefrom,
or the Subject Interests attributable thereto.
"Existing Well Gross Proceeds" means, for each Computation Period, an
amount equal to that portion of Gross Proceeds for such Computation Period
attributable to Subject Hydrocarbons produced from the Existing Wells.
"Existing Wells" means (a) the Designated Wells, to the extent such
Designated Wells are drilled and completed in a geological formation or horizon
at or above the base of the Devonian Shale, (b) the Designated Wells, to the
extent such Designated Wells are redrilled or deepened to, and/or recompleted
in, a geological formation or horizon at or above the base of the Devonian
Shale, and (c) any well in which Assignor owns an interest that is located on
the Subject Lands within 1,000 feet of the wellbore of a Designated Well and for
which initial drilling operations are commenced on or after the Effective Date,
to the extent such well is drilled and completed in a geological formation or
horizon at or above the base of the Devonian Shale; provided, however, that
"Existing Wells" shall not include any Excluded Well.
"Hydrocarbons" means oil, gas and all other minerals produced in
association with oil or gas (including, but not limited to, helium, sulphur,
nitrogen and carbon dioxide), but excluding all other minerals, whether similar
or dissimilar.
-3-
<PAGE> 4
"MMBtu" means one million British thermal units.
"Net Proceeds" means, for each Computation Period, the excess of
Aggregate Gross Proceeds for such Computation Period over Aggregate Deductible
Costs for such Computation Period.
"New Well Deductible Costs" means, for each Computation Period, an
amount equal to that portion of Deductible Costs for such Computation Period
attributable to the New Wells, the Subject Hydrocarbons produced therefrom or
the Subject Interests attributable thereto.
"New Well Gross Proceeds" means, for each Computation Period, an amount
equal to that portion of Gross Proceeds for such Computation Period attributable
to Subject Hydrocarbons produced from the New Wells.
"New Wells" means (a) all oil and gas wells in which Assignor owns an
interest that are located on the Subject Lands and for which initial drilling
operations are commenced on or after the Effective Date (except wells described
in clause (c) of the definition of Existing Wells) and (b) the Designated Wells
to the extent such wells are drilled or deepened to, or completed in, a
geological formation or horizon below the base of the Devonian Shale; provided,
that "New Wells" shall not include any Excluded Well.
"Non-Affiliate" means, as to the party specified, any Person who is not
an Affiliate of such party.
"NYMEX Price" means ________________________.
"Overhead Rate" shall mean the fee charged by Assignor in accordance
with Article IV of the Accounting Procedure.
"Person" means any individual, corporation, partnership, limited
partnership, limited liability company, trust, estate or other entity,
organization or association.
"Prime Interest Rate" means the variable rate of interest most recently
announced by [Bank One Texas, N.A.] (or its successor) as its "prime rate."
"Producing Well Fixed Fee" shall mean the fee charged by Assignor in
accordance with Article IV of the Accounting Procedures.
"Quarterly Payment Date" means, for each Computation Period, the close
of business on the 25th day of the third calendar month following the end of
such Computation Period which is not a Saturday, Sunday or other day on which
national banking institutions in the City of Fort Worth, Texas are closed as
authorized or required by law, then the Quarterly Payment Date shall be the next
business day following such closure.
-4-
<PAGE> 5
"Sale" and "Sold" mean all forms of dispositions of Subject
Hydrocarbons for value, including exchanges and other dispositions for value.
"Sales Contracts" means all contracts and agreements for the sale of
Subject Hydrocarbons.
"Subject Hydrocarbons" means all Hydrocarbons in and under, and which
may be produced, saved and Sold from, and which shall accrue and be attributable
to, the Subject Interests, other than Coal Bed Methane.
"Subject Interests" means, subject to the exclusions stated below, each
kind and character of right, title and interest which Assignor owns on the
Effective Date in or under the Subject Leases, and all the right, title and
interest which Assignor owns on the Effective Date in and to the Subject Lands,
whether such right, title or interest be under and by virtue of a lease, a
unitization or pooling agreement or order, an operating agreement, a farmout
agreement, a division order, a transfer order or any other type of agreement,
conveyance, assignment or instrument or under any other type of claim or title,
legal or equitable, recorded or unrecorded even though Assignor's interests be
incorrectly or incompletely described in, or a description thereof be omitted
from, Exhibit A, all as the same shall be enlarged by the discharge of any
payments out of production or by the removal of any charges or encumbrances to
which any of the same are subject and any and all renewals and extensions of any
of the same, but subject to all burdens to which Assignor's right, title or
interest is subject (while same remains so subject), limited, however, if
Assignor's interest in any Subject Interest should terminate at any time, to the
period to which Assignor's interest in such Subject Interest is limited. There
shall be excluded from the term "Subject Interests" (a) all Excluded Interests,
and (b) any interest hereafter acquired by Assignor in and to any of the Subject
Lands, except any interest acquired pursuant to existing agreements for no new
consideration and renewals or extensions of existing Subject Leases. For
purposes of this Conveyance "renewals or extensions" of any Subject Lease shall
be limited to renewals or extensions of an existing Subject Lease obtained by
the present owner thereof (or such owner's successors in interest) while such
Subject Lease is in force or within six months after such Subject Lease
terminates. Assignor shall be under no duty to seek renewals or extensions of
any Subject Lease.
"Subject Lands" means, subject to the exclusions below, the lands which
are described in and which are covered by the Subject Leases, provided that, (a)
there shall be excluded from the term "Subject Lands" all lands and depths that
are part of the Excluded Interests and (b) where the description in Exhibit A
excepts land or refers to an instrument insofar only as it covers certain land
or certain depths in certain land, no interest in such excepted land or depths
or in land other than to which such reference is limited shall be included in
the terms "Subject Lands" or "Subject Interests".
"Subject Leases" means each oil and gas lease, oil, gas and mineral
lease, oil and gas sublease, mineral deed, royalty deed, assignment, deed,
pooling agreement, unitization agreement or other document of title described on
Exhibit A attached hereto.
-5-
<PAGE> 6
"Tax Accrual" means, for each Computation Period, an amount that may be
set aside by Assignor as an accrual to be applied against Taxes other than those
that are deducted or excluded from Gross Proceeds, which accruals shall be
adjusted to the extent actual Taxes paid differ.
"Taxes" means the sum of all general property (ad valorem), production,
severance, sales, gathering and excise taxes and other taxes (whether state,
federal or otherwise), except income taxes, assessed or levied on or in
connection with the Subject Interests, the Royalty Interest or the production
therefrom or equipment on the Subject Lands, or against Assignor as owner of the
Subject Interests or Assignee as owner of the Royalty Interest.
"Trust" means the Appalachian Natural Gas Trust established by the
Trust Indenture.
"Trust Indenture" means the Trust Indenture by and between Eastern
States Oil & Gas, Inc. and Band One Texas, N.A. and Bank One Delaware, Inc.
dated as of September 1, 1999, establishing the Appalachian Natural Gas Trust, a
Delaware business trust.
ARTICLE II
DEDUCTIBLE COSTS; GROSS PROCEEDS
SECTION 2.01. Deductible Costs. As used herein the term "Deductible
Costs" means, for each Computation Period, to the extent not excluded for
purposes of calculating Gross Proceeds, whether capital or non-capital in
nature,
(a) the sum of the following (without duplication):
(i) all amounts paid by Assignor or any Affiliate of Assignor for any
of the following:
(A) royalty, overriding royalty or other presently existing
burdens against production or the proceeds of Sale of production
attributable to the Subject Interests; and
(B) delay rentals, shut-in gas well royalty or payments, and
minimum royalty payments; and
(C) payments to lessors or others in the area in connection with
the drilling or deferring of drilling of any well on any of the Subject
Lands or lands in the vicinity thereof (including dry and bottom hole
payments and payments made to others for refraining from drilling an
offset well) or in connection with any adjustment of any well and
leasehold equipment upon unitization of any of the Subject Interests;
and
(D) rent and other consideration paid for use of or damage to the
surface;
(ii) the Tax Accrual and other taxes or fees, to any governmental
authority paid by Assignor in connection with the recording or filing of the
Conveyance; and
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<PAGE> 7
(iii) with respect to any Subject Interests (whether Assignor or any
Affiliate of Assignor is the operator of such Subject Interest and whether such
Subject Interest is subject to a joint operating agreement) the Drilling
Overhead Fee, the applicable Producing Well Fixed Fee, and Overhead Rate, all as
subject to adjustment as set forth in the Accounting Procedure and proportionate
reduction as set forth in Section 2.03 hereof; and
(iv) the direct charges set forth in Article II of the Accounting
Procedure, the gathering and compression fees and charges set forth in Article
III of the Accounting Procedure; and
(v) all other costs, expenses and liabilities paid or incurred by
Assignor or any Affiliate of Assignor for investigating, exploring, prospecting,
drilling and mining for, operating and producing Subject Hydrocarbons and the
Sale and marketing thereof including, without limitation, the following:
(A) costs and expenses for acquisition, processing and
interpretation of geological, geophysical and engineering data; and
(B) costs for drilling, equipping, plugging back, reworking,
completing, recompleting and plugging and abandoning any well on the
Subject Lands and making the Subject Hydrocarbons ready or available
for market; and
(C) costs for construction and operation of gathering lines,
tanks, transmission lines, meters and other production and delivery
facilities; and
(D) costs, whether paid in cash or by a share of Subject
Hydrocarbons, of transporting, gathering, compressing, dehydrating,
processing, separating, treating, storing and marketing the Subject
Hydrocarbons and disposing of extraneous substances produced in
association with Subject Hydrocarbons; and
(E) costs for secondary recovery, pressure maintenance,
repressuring, cycling and other operations conducted for the purpose of
enhancing production; and
(F) costs or expenses (whether paid in cash or by delivery of gas)
incurred in resolving overproduced gas imbalances attributable to the
Subject Interests as of the Effective Date and thereafter; and
(G) costs for litigation concerning title to or operation of the
Subject Interests and any other acts or omissions of Assignor
consistent herewith or brought by Assignor to protect the Subject
Interests; and
(H) costs for litigation or regulatory proceedings concerning
title to or operation of the Subject Interests and any other acts or
omissions of Assignor consistent herewith or brought by Assignor to
protect the Subject Interests or to protect or enforce any rights,
contractual or otherwise, of Assignor to produce or market Subject
Hydrocarbons therefrom;
-7-
<PAGE> 8
(vi) any amounts paid by Assignor or any Affiliate of Assignor whether
as refund, interest or penalty, to a purchaser or any governmental agency or
other Person because the amount initially received by Assignor (or Affiliate of
Assignor) as sales price for Sales after the Effective Date was more or
allegedly more than permitted by the term of any applicable contact, statute,
regulation, order, decree or other obligation; provided such amount (in the case
of a refund), or the amounts with respect to which the interest or penalty was
paid, were previously included in Gross Proceeds;
(vii) any other amounts paid by Assignor or any Affiliate of Assignor
with respect to ownership or operation of the Subject Interests after the
Effective Date or Sales of production therefrom after the Effective Date,
whether as refund, fine, damages, interest or penalty pursuant to litigation or
settlement of threatened litigation by any third Person or governmental agency,
provided that Assignor has not breached Section 7.01 hereof;
(viii) all consideration hereafter paid and costs and expenses
hereafter incurred by Assignor or any Affiliate of Assignor for any renewals or
extensions of Leases or other rights acquired after the Effective Date which are
included in the definition herein of Subject Interests; and
(ix) any prepayment which Assignor or any Affiliate of Assignor may, at
its election, charge to Deductible Costs for services, materials, supplies,
equipment or other cost or expense related to the Subject Interests which are
reasonably expected to be incurred no later than 180 days following the
Computation Period in which such prepayment is included as a Deductible Cost,
and which prepayment is in lieu of charging the cost or expense when actually
incurred by Assignor (or Affiliate of Assignor); provided, however, that such
amounts shall be adjusted if and to the extent actual cost or expenses differ
from such prepayment and shall be credited against future Deductible Costs to
the extent the actual cost or expense for which such prepayment was made is not
actually incurred by Assignor (or Affiliate or Assignor) within 180 days
following the Computation Period in which such prepayment is included as a
Deductible Cost;
(x) any accrual or reserve which Assignor or any Affiliate of Assignor
shall have the right, at its election, to charge to Deductible Costs for
operations budgeted under an operating agreement or approved under an
authorization for expenditures ("AFE"), which accrual or reserve may be based on
the reasonably expected time of performing such operation or on an estimated
percentage of completion of the operation or on any other reasonable method, and
which accrual is in lieu of charging the cost of such operation when paid for by
Assignor (or Affiliate of Assignor) but which shall be adjusted if and to the
extent actual costs differ from such accrual or reserve;
(b) but excluding
(i) the overhead costs paid by Assignor under any joint operating
agreement applicable to any of the Subject Interests where Assignor or any
Affiliate of Assignor is not the operator of such Subject Interest; and
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<PAGE> 9
(ii) costs which would otherwise be treated as Deductible Costs (but
which shall not be so treated for purposes hereof until the following amounts
have been fully credited against such costs) equal to amounts reimbursed or
credited to Assignor by insurance from damage to property, by sales of property
or transfers of property off the leases included in the Subject Interests or by
proceeds from unitization or other disposition of property; and
(iii) except for resolution of gas imbalances which are included in
subclause (a)(v)(F) of this Section 2.01, any amounts that otherwise would be
Deductible Costs but which are attributable to periods before the Effective
Date; and
(iv) any amount that otherwise would be treated as a Deductible Cost
but which is attributable to claims or causes of action against Assignor arising
out of operations or other activities on the Subject Lands or related to the
Subject Interests occurring prior to the Effective Date, including litigation
costs and settlement costs with respect to such claims or causes of action; and
(v) costs that otherwise would be treated as Deductible Costs but which
have already been excluded or deducted from Gross Proceeds; and
(vi) costs incurred by any Affiliate of Assignor for which such
Affiliate has received a fee, reimbursement or other payment from Assignor,
where such payment by Assignor constitutes a Deductible Cost.
SECTION 2.02. Allocation of Deductible Costs. To the extent operating
expenses or other Deductible Costs relate to operations for both an Existing
Well and a New Well, such Deductible Costs shall be allocated to Existing Well
Deductible Costs and New Well Deductible Costs in the proportion such operations
apply to the Existing Well and the New Well, as determined by Assignor in its
reasonable discretion.
SECTION 2.03 Proportionate Reduction of Certain Deductible Costs. If
Assignor owns less than 100% working interest in any Existing Well or New Well,
the Drilling Overhead Fee, the applicable Producing Well Fixed Fee and Overhead
Rate chargeable as Deductible Costs under Section 2.01(a)(iii) shall be
proportionately reduced with respect to such well. For example, if Assignor owns
a 50% working interest in such well, then only 50% of the Drilling Overhead Fee,
the applicable Producing Well Fixed Fee and Overhead Rate for such well shall be
included as Deductible Costs.
SECTION 2.04. Gross Proceeds. As used herein, the term "Gross Proceeds"
means, for each Computation Period, the proceeds received by Assignor from the
Sale of Subject Hydrocarbons produced and Sold during such Computation Period
(whether such proceeds are received during or after such Computation Period),
plus or minus any amount representing adjustments or corrections made in such
Computation Period to Gross Proceeds for any prior Computation Period to the
extent such adjustment or correction results from prior estimations or
inaccuracies in the calculation of Gross Proceeds, but in all instances subject
to the following:
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(a) There shall be excluded from Gross Proceeds all Taxes that are
deducted or excluded from proceeds of Sale received by Assignor.
(b) There shall be excluded from Gross Proceeds any amount for Subject
Hydrocarbons attributable to nonconsent operations conducted with respect to the
Subject Interests (or any portion thereof) as to which Assignor shall be a
nonconsenting party and which is dedicated to the recoupment or reimbursement of
costs and expenses of the consenting party or parties by the terms of the
relevant operating agreement, unit agreement, contract for development or other
instrument providing for such nonconsent operations. Assignor agrees that its
election not to participate in such operations shall be made in conformity with
the provisions of Section 7.01 of this Conveyance, but third persons shall not
be under any duty to determine that such election so conformed.
(c) There shall be excluded from Gross Proceeds any amount which
Assignor shall receive as any of the following:
(i) consideration for transfer or sale of any of the Subject
Interests (subject to the Royalty Interest) or equipment, gathering lines,
pipelines or other personal property or fixtures on the Subject Lands; and
(ii) payments for gas not taken, when such payments are made (but
to the extent such payments are allocated to gas taken in the future such
payments shall be included without interest in Gross Proceeds when such gas is
taken); and
(iii) damages arising from any cause other than drainage or
reservoir injury; and
(iv) rental for reservoir use; and
(v) payments made to Assignor in connection with the drilling of
any well on any of the Subject Lands or lands in the vicinity thereof (such
exclusion including dry and bottom hole payments, provided that if such well is
drilled on the Subject Lands and Assignor incurs Deductible Costs in connection
therewith such payments shall reduce Deductible Costs); and
(vi) payments made to Assignor in connection with any adjustment of
any well and leasehold equipment upon unitization of any of the Subject
Interests; and
(vii) payments made to Assignor in connection with the shutting-in
of any well on any of the Subject Lands; and
(viii) proceeds received from the Sale of Subject Hydrocarbons that
are produced prior to the Effective Date.
(d) There shall be excluded from Gross Proceeds any amount for Subject
Hydrocarbons lost in the production (including volumes vented into the
atmosphere as a result of operations), treating, gathering, compressing or
marketing thereof (including line loss) or used by Assignor in
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conformity with ordinary or prudent practices for drilling, production and plant
operations (including gas injection, secondary recovery, pressure maintenance,
repressuring, cycling operations, compressor or plant fuel or shrinkage)
conducted for the purpose of drilling for, producing or processing Subject
Hydrocarbons or for operations on any unit or plant to which the Subject
Interests are committed, but only so long as such Subject Hydrocarbons are so
used.
(e) Amounts received as a loan by Assignor from a purchaser of Subject
Hydrocarbons, whether with or without interest, shall not be considered to be
derived from the Sale of Subject Hydrocarbons or included as Gross Proceeds.
(f) Advance or prepaid payments for future production of Subject
Hydrocarbons received by Assignor shall be included in Gross Proceeds when
received to the extent not subject to repayment in the event of insufficient
subsequent product (and to the extent so subject to repayment shall be included
without interest in Gross Proceeds when the Subject Hydrocarbons on which such
payment was so advanced or prepaid are actually produced).
(g) Cash payments received by Assignor in respect of any lease or
farmout entered into by Assignor with respect to the Subject Interests as
contemplated under Section 7.04 hereof shall be included in Gross Proceeds when
such payment is received by Assignor.
(h) If a controversy or possible controversy exists (whether by reason
of any statute, order, decree, rule, regulation, contract or otherwise) between
Assignor and any purchaser as to the correct sales price of any Subject
Hydrocarbons or, for any other reason, as to Assignor's right to receive or
collect the proceeds of Sale of any Subject Hydrocarbons, then
(i) amounts withheld by the purchaser or deposited by it with an
escrow agent shall be excluded from Gross Proceeds until the Computation Period
in which such amounts are actually collected by Assignor, but the amounts then
so included in Gross Proceeds shall include any interest, penalty or other
amount paid to Assignor in respect thereof,
(ii) amounts received by Assignor and promptly deposited by it with
an escrow agent shall be excluded from Gross Proceeds, but all amounts
thereafter paid to Assignor by such escrow agent shall be included in Gross
Proceeds in the Computation Period in which such amounts are paid to Assignor;
and
(iii) amounts received by Assignor and not deposited with an escrow
agent shall be included in Gross Proceeds for the applicable Computation Period.
(i) Gross Proceeds for each month during the calendar year of 2000
shall be subject to adjustment in the manner provided for in Section 2.05.
SECTION 2.05. Adjustments to Gross Proceeds. If the NYMEX Price for
natural gas sales settled in any month during 2000 is less than $2.50 per MMBtu,
then the Gross Proceeds for such month shall be increased by an amount equal to
the product of (a) $2.50 minus such NYMEX Price for that month multiplied by (b)
that portion of the Subject Hydrocarbons produced and Sold during
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such month that is natural gas (such portion to be expressed and measured in
MMBtu's). If the NYMEX Price for natural gas sales settled in any month during
2000 is greater than $2.90 per MMBtu, then the Gross Proceeds for such month
shall be reduced by an amount equal to the product of (y) the NYMEX Price for
that month minus $2.90 multiplied by (z) that portion of the Subject
Hydrocarbons produced and Sold during such month that is natural gas (such
portion to be expressed and measured in MMBtu's). The foregoing adjustments to
Gross Proceeds shall be made only for Subject Hydrocarbons produced and Sold
during the calendar year of 2000.
ARTICLE III
MARKETING OF SUBJECT HYDROCARBONS
SECTION 3.01. Sales Contracts. Assignor, to the extent it has the right
to do so, shall market or cause to be marketed the Subject Hydrocarbons and
Assignee shall have no authority to market the Subject Hydrocarbons or to take
in-kind any Subject Hydrocarbons. For such purpose, Sales of Subject
Hydrocarbons may continue to be made pursuant to existing Sales Contracts.
Assignor may amend such existing Sales Contracts and may enter into one or more
Sales Contracts in the future at the prices and on the terms Assignor shall deem
proper in Assignor's sole and absolute discretion, which may include sales to
Affiliates of Assignor. Further, Assignor may commit any of the Subject
Interests (including the Royalty Interest attributable thereto) to one or more
agreements for processing pursuant to which, by way of example and not by way of
limitation, the plant owner or operator (which may be an Affiliate of Assignor)
receives a portion of the Subject Hydrocarbons or plant products derived
therefrom or proceeds of the Sale thereof as a fee for processing. Subject to
Section 2.05, Gross Proceeds of Subject Hydrocarbons shall be determined on the
basis of amounts actually received by Assignor (and not proceeds received by any
of Assignor's Affiliates) from Sales under Sales Contracts regardless of whether
at the time of production or Sale market value should be different from proceeds
of Sale. In no event shall Gross Proceeds or Deductible Costs include any
revenues, expenses, gains or losses resulting from option transactions, swaps,
collars, floors, caps or other futures or hedging transactions which, if engaged
in by Assignor or any of its Affiliates in respect of Subject Hydrocarbons,
shall be solely for the account of Assignor or such Affiliate.
SECTION 3.02. Delivery of Subject Hydrocarbons. All Subject
Hydrocarbons Sold by Assignor shall be delivered by Assignor to the purchasers
thereof into the pipelines to which the wells producing such Subject
Hydrocarbons may be connected or to such other point of purchase as is
reasonably required in the marketing of such Subject Hydrocarbons.
SECTION 3.03. Reliance by Third Party. As to any party, the acts of
Assignor with respect to the Sale of Subject Hydrocarbons shall be binding on
Assignee. It shall not be necessary for Assignee to join with Assignor in any
division or transfer order, or Sales Contract, and proceeds of Sale of the
Subject Hydrocarbons shall be paid by the purchasers thereof (or others
disbursing proceeds) directly to Assignor without necessity of joinder by or
consent of Assignee.
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ARTICLE IV
PAYMENTS
SECTION 4.01. Payments. On or before each Quarterly Payment Date,
beginning with the Quarterly Payment Date for the Computation Period ending
September 30, 1999, Assignor shall pay to Assignee in respect of the Royalty
Interest an amount equal to the Net Proceeds for the immediately preceding
Computation Period. Gross Proceeds shall not include any interest on proceeds
received by Assignor prior to the payment dates provided for in this Section
4.01.
SECTION 4.02. Interest on Past Due Payments. Except as otherwise
provided in Section 10.05 hereof, any amount not paid by Assignor to Assignee
when due shall bear, and Assignor will pay, interest determined at the end of
each month, from such due date until such amount is paid, at the rate of the
lesser of (a) the Prime Interest Rate and (b) the maximum lawful contract rate
of interest permitted by the applicable usury laws, now or hereafter enacted,
which interest rate (the "Maximum Rate") shall change when and as said laws
change, effective at the close of business on the day such change in said laws
becomes effective; but, if there shall be no Maximum Rate, then the rate shall
be specified in the foregoing clause (a).
SECTION 4.03. Overpayment. If at any time Assignor pays Assignee more
than the amount due, Assignee shall not be obligated to return any such
overpayment, but the amount or amounts otherwise payable to Assignee for any
subsequent period or periods shall be reduced by such overpayment plus an amount
equal to interest during the period of such overpayment at the rate of the
lesser of (a) the Prime Interest Rate and (b) the Maximum Rate; but if there
shall be no Maximum Rate, then the rate shall be as specified in the foregoing
clause (a).
ARTICLE V
RECORDS AND REPORTS
SECTION 5.01. Books and Records. Assignor shall at all times maintain
true and correct books and records sufficient to determine the amounts payable
to Assignee hereunder, including, but not limited to, a Net Proceeds account to
which Aggregate Gross Proceeds and Aggregate Deductible Costs are credited and
charged.
SECTION 5.02. Inspections. The books and records referred to in Section
5.01 shall be open for inspection by Assignee and its agents and representatives
at the office of Assignor during normal business hours and after reasonable
advance notice.
SECTION 5.03. Quarterly Statements. Within 90 days after the close of
each Computation Period, Assignor shall deliver to Assignee a statement showing
the computation of Net Proceeds attributable to such Computation Period.
SECTION 5.04. Annual Audits and Reports. Within 120 days after the end
of each calendar year, Assignor shall deliver to Assignee a statement which has
been audited by a
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nationally recognized firm of independent public accountants selected by
Assignor, which shall show the information provided for in Section 5.03 on an
annual basis. Assignee shall bear the cost of each such audit.
SECTION 5.05. Assignee's Exceptions to Quarterly Statements. If
Assignee objects to any items or matters included in the quarterly or audited
annual statements provided by Assignor, Assignee shall notify Assignor in
writing setting forth in such notice the specific items and matters to which
Assignee objects and, with respect to the objections that are justified,
adjustment shall be made. With respect to each audited annual statement
delivered by Assignor under Section 5.04, if Assignee shall fail to give
Assignor written notice of any objection to such audited annual statement (or
the quarterly statements provided by Assignor for such year) within 90 days
after such annual audited statement is delivered to Assignee, then all the
statements for such calendar year shall be deemed to be correct for all
purposes.
SECTION 5.06. Geological and Other Data. Upon request by Assignee,
Assignor shall, subject to the limitations of confidentiality or nondisclosure
obligations to co-owners or other third parties, furnish to Assignee access to
all geological, well and production data which Assignor has on hand relating to
operations on the Subject Interests. Assignor shall make such data available for
review by Assignee during Assignor's normal business hours at its principal
place of business. Assignor will use reasonable efforts to obtain waivers of any
such confidentiality or nondisclosure obligations that prevent it from providing
to Assignee any requested information, but Assignor shall not be obligated to
incur any expense or detriment above a nominal amount to obtain such waiver.
Assignor shall also furnish to Assignee, upon request by Assignee, reports
showing the status of development, producing and other operations conducted by
Assignor on the Subject Interests. Assignor shall, upon request by Assignee,
furnish to Assignee all reserve reports or studies in the possession of Assignor
from time to time relating to the Subject Interests, whether prepared by
Assignor or by third party consulting engineers; provided, it is agreed that
Assignor makes no representations or warranties as to the accuracy or
completeness of any such reports or studies and shall have no liability to
Assignee or any other Person resulting from their use of such reports or
studies, and Assignee agrees not to attribute to Assignor or such third-party
consulting engineers any such reports or studies or the contents thereof in any
securities filings or reports to owners or holders of "Beneficial Interests" in
the Trust. All information furnished to Assignee pursuant to this section is
confidential and for the sole benefit of Assignee and shall not be shown by
Assignee to any other Person, except that this provision shall not prohibit the
disclosure by Assignee of any information that (i) at the time of disclosure is
generally available to the public (other than as a result of a disclosure by
Assignee), (ii) was available to Assignee on a nonconfidential basis from a
source other than Assignor, provided that such source is not known by Assignee
to be bound by a confidentiality obligation owed to Assignor, or (iii) Assignee
is legally required to disclose, provided that Assignee has given to Assignor
notice of such requirement and a reasonable opportunity to seek at Assignor's
expense, a protective order and other appropriate relief from such requirement.
SECTION 5.07. Reserve Reports. Assignor may, but is not obligated to,
provide an annual reserve report for the Royalty Interest prepared by
independent consulting reservoir engineers. If such reserve report is provided
by Assignor, Assignee will reimburse Assignor for the cost thereof.
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ARTICLE VI
LIABILITY OF ASSIGNEE
In no event shall Assignee be liable or responsible in any way for any
Deductible Costs (including Aggregate Excess Deductible Costs) or other costs or
liabilities incurred by Assignor or others attributable to the Subject Interests
or to the Subject Hydrocarbons produced therefrom.
ARTICLE VII
OPERATION OF SUBJECT INTERESTS
SECTION 7.01. Reasonably Prudent Operator Standard. Assignor agrees, to
the extent it has the legal right to do so under the terms of any lease,
operating agreement, contract for development or similar instrument affecting or
pertaining to the Subject Interests (or any portion thereof), that it will
conduct and carry on the maintenance and operation of the Subject Interests in
accordance with good oil and gas field practices as would a reasonably prudent
operator under the same or similar circumstances in order to protect the Subject
Interests from drainage. However, nothing contained in this Section 7.01 shall
be deemed to prevent or restrict Assignor from electing not to participate in
any operation which is to be conducted under the terms of any operating
agreement, contract for development or similar instrument affecting or
pertaining to the Subject Interests (or any portion thereof) and allowing
consenting parties to conduct nonconsent operations thereon, if such election is
made by Assignor in accordance with the reasonably prudent operator standard set
forth in this Section 7.01. NOTWITHSTANDING ANYTHING ELSEWHERE HEREIN TO THE
CONTRARY, ASSIGNOR SHALL NEVER BE LIABLE TO ASSIGNEE OR THE TRUST FOR THE MANNER
IN WHICH ASSIGNOR PERFORMS ITS OBLIGATIONS AND DUTIES HEREUNDER SO LONG AS
ASSIGNOR HAS ACTED IN ACCORDANCE WITH THE REASONABLY PRUDENT OPERATOR STANDARD
SET FORTH IN THIS SECTION 7.01. ASSIGNOR EXPRESSLY DISCLAIMS ANY FIDUCIARY DUTY
OR FIDUCIARY OBLIGATION IN FAVOR OF ASSIGNEE OR THE TRUST.
SECTION 7.02. Abandonment of Properties. Nothing herein contained shall
obligate Assignor to continue to operate any well or to operate or maintain in
force or attempt to maintain in force any of the Subject Interests when, in
Assignor's opinion, such well or Subject Interest ceases to produce or is not
capable of producing Hydrocarbons in paying quantities. The expiration of a
Subject Interest in accordance with the terms and conditions applicable thereto
shall not be considered to be a voluntary surrender or abandonment thereof
SECTION 7.03. Insurance. Although Assignor is permitted to carry
policies of insurance covering the property upon the Subject Interests and risks
incident to the operation thereof and to include premiums therefor as Deductible
Costs, Assignor shall not be required to carry insurance on such property or
covering any of such risks unless it elects to do so. In no event shall Assignor
be liable to Assignee on account of any losses sustained which are not covered
by insurance.
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SECTION 7.04. Certain Rights to Manage the Subject Interests.
Notwithstanding anything in this Conveyance to the contrary, Assignor shall have
the right and power, acting in good faith and as a reasonably prudent oil and
gas operator, to execute, deliver, and perform operating agreements, oil and gas
leases, farmout agreements, exploration agreements, participation agreements,
drilling agreements, acreage contribution agreements, dry-hole agreements,
bottom-hole agreements, and other similar instruments and agreements that cover
or affect the Subject Interests and to make all decisions or elections required
thereunder, including, but not limited to, decisions to consent or non-consent
to drilling and other operations. The applicable Royalty Interest shall in each
case be bound by such instrument or agreement (and decisions or elections
thereunder), without the necessity of any execution, consent, joinder, or
ratification by Assignee, and the Royalty Interest shall thereafter be
calculated and paid with respect to the interests reserved, obtained, or
modified by Assignor in such transaction, not by reference to the Subject
Interests that existed before such transaction. For example, but not by way of
limitation, (a) Assignor may farm out any Subject Interest that is an oil and
gas lease, and the Subject Interest therein shall subsequently be the overriding
royalty interest, reversionary working interest, and/or other rights and
interests reserved by Assignor in the farmout, not the original leasehold
interest, or (b) Assignor may execute an oil and gas lease to cover any Subject
Interest that is a mineral interest, and the Subject Interest shall subsequently
be the royalty and other lease benefits obtained or reserved by Assignor in such
lease, not the original mineral interest.
ARTICLE VIII
POOLING AND UNITIZATION
SECTION 8.01. Pooled Subject Interests. To the extent any of the
Subject Interests have been heretofore pooled and unitized for the production of
Hydrocarbons, such Subject Interests are and shall be subject to the terms and
provisions of such pooling and unitization agreements, and the Royalty Interest
in each such Subject Interest shall apply to and affect only the production from
such units which accrues to such Subject Interest under and by virtue of the
applicable pooling and unitization agreements.
SECTION 8.02. Right to Pool and Unitize. Assignor shall have the
exclusive right and power (as between Assignor and Assignee), exercisable only
during the period provided in Section 8.03 hereof, to pool or unitize any of the
Subject Interests and to alter, change or amend or terminate any pooling or
unitization agreements heretofore or hereafter entered into, as to all or any
part of the Subject Lands, as to any one or more of the formations or horizons
thereunder, and as to any one or more Hydrocarbons, upon such terms and
provisions as Assignor shall in its sole and absolute discretion determine,
including, without limitation, the pooling of any of the Subject Lands with any
of the Excluded Interests. If and whenever through the exercise of such right
and power, or pursuant to any law hereafter enacted or any rule, regulation or
order of any governmental body or official hereafter promulgated, any of the
Subject Interests are pooled or unitized in any manner, the Royalty Interest
insofar as it affects such Subject Interest shall also be pooled and unitized,
and in any such event such Royalty Interest in such Subject Interest shall apply
to and affect only the production which accrues to such Subject Interest under
and by virtue of the
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pooling and unitization, and it shall not be necessary for Assignee to agree to,
consent to, ratify, confirm or adopt any exercise of such right and power by
Assignor.
SECTION 8.03. Applicable Period. Assignor's power and rights in Section
8.02 shall be exercisable only during the period of the life of the last
survivor of the descendants of the signers of the Declaration of Independence
living on the date of execution hereof, plus twenty-one (21) years after the
death of such last survivor, or the term of this Conveyance, whichever period
shall first expire.
ARTICLE IX
GOVERNMENT REGULATION
All obligations of Assignor hereunder shall be subject to all present
and future valid federal, state and local laws, statutes, codes and orders; and
all applicable rules, orders, regulations and decisions of every court,
governmental agency, body or authority having jurisdiction over the Hydrocarbons
in and under and that may be produced from the Subject Interests. Assignor's
obligations are specifically, but not by way of limitation, subject, to the
extent in effect, to all applicable provisions of the Emergency Petroleum
Allocation Act of 1973, the Department of Energy Organization Act, the Natural
Gas Act, the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol
Act of 1989 and each other statute purporting to provide regulation of the Sale
of Hydrocarbons or establishing maximum prices at which the same may be Sold and
all applicable laws, orders, rules and regulations thereunder of the Federal
Energy Regulatory Commission, the Department of Energy and each other
legislative or governmental body, agency, board or commission having
jurisdiction. If maximum rates permitted under such statutes, rules and
regulations for the Subject Hydrocarbons are lower than prices established in
Sales Contracts, then the lower regulated prices received by Assignor shall
control. Assignor shall be entitled to use its reasonable discretion in making
filings, for itself and on behalf of Assignee, with the Federal Energy
Regulatory Commission, the Department of Energy or any other governmental body,
agency, board or commission having jurisdiction, affecting the price or prices
at which Subject Hydrocarbons may be Sold, and with purchasers of production,
operators or others with respect to any excise tax.
ARTICLE X
ASSIGNMENTS
SECTION 10.01. Assignment by Assignor. Assignor shall have the right to
assign, sell, transfer, convey, mortgage or pledge the Subject Interests, or any
part thereof, subject to the Royalty Interest and the term and provisions of
this Conveyance. From and after the effective date of any such assignment, sale,
transfer or conveyance by Assignor, the assignee thereunder shall succeed to all
the requirements upon and responsibilities of Assignor hereunder, as to the
interests in the Subject Interests so acquired by such assignee, and, from and
after the such effective date, Assignor shall be relieved of such requirements
and responsibilities, excepting only those accrued or due for performance prior
to such effective date.
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SECTION 10.02. Partial Assignment. If Assignor assigns its interest
under the Subject Interests as to some of such Subject Interests or as to some
part thereof, then, effective as of the date of such assignment, in determining
the Royalty Interest payable with respect to production from such assigned
Subject Interests or parts thereof, the Aggregate Gross Proceeds, Aggregate
Deductible Costs and Net Proceeds attributable to such assigned interests will
be computed and determined by the assignee of such assigned interests in the
aggregate as to the assigned interests owned by such assignee, but separate from
and not aggregated with the computation and determination made by Assignor as to
Subject Interests that have not been assigned by Assignor.
SECTION 10.03. Assignment by Assignee. Assignee has the right to assign
the Royalty Interest in whole or in part only as authorized by the Trust
Indenture. However, no such assignment will affect the method of computing Net
Proceeds, and if more than one Person becomes entitled to participate in the
Royalty Interest, Assignor may withhold from such other Person payments to which
such Person would otherwise be entitled hereunder and the furnishing of any data
or information which Assignor is required by the terms hereof to furnish
Assignee until Assignor is furnished a recordable instrument executed by or
binding upon all Persons interested in the Royalty Interest designating one
Person who is to receive such payments, data and information. In making
conveyances or assignments of any of the Subject Interests (to the extent
permitted hereunder), Assignee need not vest in its grantee or assignee all of
the rights of Assignee hereunder with respect to the interest in the Subject
Interests so conveyed or assigned.
SECTION 10.04. Certain Sales of Subject Interests. Subject to the
limitations set forth in Section ______ of the Trust Indenture, Assignor may
cause the sale of certain Subject Interests, including the appurtenant Royalty
Interest from time to time and Assignee will join in such sales as provided in
the Trust Indenture. The proceeds of any such sale shall be apportioned and paid
as provided in the Trust Indenture, but the purchasers of such Subject Interests
(inclusive of the appurtenant Royalty Interest) may pay the full amount of the
purchase price therefor to Assignor and shall have no responsibility to see to
the proper allocation thereof between Assignor and Assignee.
SECTION 10.05. Change in Ownership. No change of ownership or right to
receive payment of the Royalty Interest, or of any part thereof, however
accomplished, shall be binding upon Assignor until notice thereof shall have
been furnished by the Person claiming the benefit thereof, and then only with
respect to payments thereafter made. Notice of sale or assignment shall consist
of a certified copy of the recorded instrument accomplishing the same; notice of
change of ownership or right to receive payment accomplished in any other manner
(for example by reason of incapacity, death or dissolution) shall consist of
certified copies of recorded documents and complete proceedings legally binding
and conclusive of the rights of all parties. Until such notice accompanied by
such documentation shall have been furnished Assignor as above provided, the
payment or tender of all sums payable on the Royalty Interest may be made in the
manner provided herein precisely as if no such change in interest or ownership
or right to receive payment had occurred, or (at Assignor's election) Assignor
shall have the right to suspend payment of such sums without interest in the
event of such change until such documentation is furnished. The kind of
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notice herein provided shall be exclusive, and no other kind, whether actual or
constructive, shall be binding on Assignor.
SECTION 10.06. Rights of Mortgagee or Trustee. If Assignee shall at any
time execute a mortgage or deed of trust covering all or part of the Royalty
Interest, the mortgagee(s) or trustee(s) therein named or the holder of any
obligation secured thereby shall be entitled, to the extent such mortgage or
deed of trust so provides, to exercise all the rights, remedies, powers and
privileges conferred upon Assignee by the terms of this Conveyance and to give
or withhold all consents required to be obtained hereunder by Assignee, but the
provisions of this Section 10.06 shall in no way be deemed or construed to
impose upon Assignor any obligation or liability undertaken by Assignee under
such mortgage or deed of trust or under the obligation secured thereby.
ARTICLE XI
MISCELLANEOUS
SECTION 11.01. Proportionate Reduction. In the event of failure or
deficiency in title to any of the Subject Interests, the portion of the
production from such Subject Interest out of which the Royalty Interest
attributable to such Subject Interest shall be payable shall be reduced in the
same proportion that such Subject Interest is reduced.
SECTION 11.02. Exercise of Preferential Rights by Third Parties.
Notwithstanding Section 11.01, if any Person claims that this Conveyance gives
rise to a preferential right of such Person to acquire any portion of the
Royalty Interest (or any of the Subject Interests), then Assignor shall
indemnify Assignee and the trustee of the Trust against any liability, expense,
damage or loss in regard to such claim and the provisions of Section _____ of
the Trust Indenture shall apply with respect to such indemnity obligation. If
such claim results in the acquisition of any portion of the Royalty Interest by
the Person claiming the preferential right then, subject to the proviso below,
Assignor shall pay to Assignee the amount determined by multiplying (i) the
product of [_____________] multiplied by the initial public offering price of
the Trust's units of beneficial interest by (ii) a fraction, the numerator of
which is the value of the portion of the Royalty Interest acquired by the Person
claiming the preferential right, as determined by reference to the standardized
measure contained in the most recent Reserve Report (as defined in the Trust
Indenture) of the Trust and the denominator of which is the value of all the
Royalty Interest as determined by reference to the standardized measure
contained in such Reserve Report; provided, however, that if the Person claiming
such preferential right makes any payment to the Trust in connection with the
acquisition of a portion of the Royalty Interest then the amount of such payment
shall be credited against Assignor's payment obligation set forth above, but not
to create a negative number.
SECTION 11.03. Assignor's Option to Repurchase Certain Royalty
Interests. Notwithstanding Section 11.01, if (a) any Subject Interest is subject
to consent to assign or similar provision in favor of a third Person under a
Subject Lease or other document or agreement pertaining to such Subject
Interest, (b) the conveyance of the portion of the Royalty Interest attributable
to such Subject Interest requires such consent, (c) the failure to obtain such
consent
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<PAGE> 20
would render Assignor's title to such Subject Interest or the conveyance
of the portion of the Royalty Interest attributable thereto void or voidable,
and (d) such consent is not obtained by Assignor within six months after the
Effective Date, then Assignor may elect to repurchase the portion of the Royalty
Interest attributable to such Subject Interest and any such repurchase shall be
exclusive of the amounts contained in Section ___ of the Trust Indenture. As
consideration for such repurchase, Assignor shall pay to Assignee the amount
determined by multiplying (i) the product of [__________] multiplied by the
initial public offering price of the trust's units of beneficial interest by
(ii) a fraction, the numerator of which is the value of the portion of the
royalty Interest repurchased as determined by reference to the standardized
measure contained in the most recent Reserve Report (as defined in the Trust
Indenture) of the Trust and the denominator of which is the value of all the
Royalty Interest as determined by reference to the standardized measure
contained in such Reserve Report. Simultaneously with such repurchase, Assignee
shall reassign the portion of the Royalty Interest repurchased by Assignor under
a recordable form of assignment reasonably acceptable to Assignor and Assignee.
SECTION 11.04. Further Assurances. Should any additional instruments of
assignment and conveyance be required to describe more specifically any
interests subject hereto, Assignor agrees to execute and deliver the same. Also,
if any other or additional instruments are required in connection with the
transfer of State, Federal or Indian lease interests in order to comply with
applicable laws, regulations or agreements, Assignor will execute and deliver
the same.
SECTION 11.05. Notices. All notices, statements, payments and
communications between the parties hereto shall be deemed to have been
sufficiently given and delivered if sent by first class United States mail,
postage prepaid, overnight courier, or if personally delivered, to the party to
whom the same is directed or to be furnished or made at the respective
addresses, as follows:
IF TO ASSIGNOR:
Eastern States Oil & Gas, Inc.
2800 Eisenhower Avenue
Alexandria, Virginia 22314
Attention:
-------------------
IF TO ASSIGNEE:
Bank One Texas, N.A.
500 Throckmorton, Suite 201
Fort Worth, Texas 76102
Attention: Corporate Trust Department
Appalachian Natural Gas Trust
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<PAGE> 21
Either party or the successors or assignees of the interest or rights or
obligations of either party hereunder may change its address or designate a new
or different address or addresses for the purposes hereof by a similar notice
given or directed to all parties interested hereunder at the time.
SECTION 11.06. Binding Effect. This Conveyance shall bind and inure to
the benefit of the successors and assigns of Assignor and Assignee.
SECTION 11.07. Governing Law. The validity, effect and construction of
this Conveyance shall be governed by the laws of the state of _______________.
SECTION 11.08. Headings. Article and Section headings used in this
Conveyance are for convenience only and shall not affect the construction of
this Conveyance.
SECTION 11.09. Substitution of Warranty. This instrument is made with
full substitution and subrogation of Assignee in and to all covenants of
warranty by others heretofore given or made with respect to the Subject
Interests or any part thereof or interest therein.
SECTION 11.10. Nature of Interest. It is the express intention of
Assignor and Assignee that the Royalty Interest is, and shall be construed for
all purposes as, a present, fully-vested and absolute conveyance of an interest
in property.
SECTION 11.11. Counterpart Execution. This Conveyance may be executed
in multiple counterparts, each of which shall be an original. Certain
counterparts may have descriptions relating to different recording jurisdictions
omitted from Exhibit A. A counterpart with all such descriptions is being filed
for record in _________ County, ____________. Where a description covers an
interest located in more than one county, such description may be included in
counterparts recorded in each county but such inclusion of the same description
in more than one counterpart does not have any cumulative effect as to the
interests covered by such description.
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<PAGE> 22
IN WITNESS WHEREOF, each of the parties hereto has caused this
Conveyance to be executed in its name and behalf and delivered as of the
Effective Date.
EASTERN STATES OIL & GAS, INC.
By:
-------------------------------------------------
Name:
-----------------------------------------------
Title:
----------------------------------------------
acting not in its
-----------------------
individual capacity but solely as the Trustee of the
Appalachian Natural Gas Trust
By:
-------------------------------------------------
Name:
----------------------------------------------
Title:
----------------------------------------------
-22-
<PAGE> 23
STATE OF )
----------- )
)
COUNTY OF )
--------
This instrument was acknowledged before me on this ______ day of
_____________, 1999, by ___________, _____________________ of Eastern States Oil
& Gas, Inc., on behalf of said corporation.
Commission Expires: ------------------------------------
Notary Public, State of
-------------
- ------------------------------
Notary Public State of Texas
STATE OF )
----------- )
)
COUNTY OF )
--------
This instrument was acknowledged before me on this ______ day of
_____________, 1999, by ___________, _____________________ of ________________,
Trustee of the Appalachian Natural Gas Trust, on behalf of said Bank as Trustee
of the Appalachian Natural Gas Trust.
Commission Expires: ------------------------------------
Notary Public, State of
-------------
- ------------------------------
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<PAGE> 24
EXHIBIT A
SUBJECT LEASES
With respect to the Conveyance for each of Kentucky and West Virginia this
Exhibit A will include a description of each "Subject Lease" (as defined in the
Conveyance) in which ESOG owns an interest in such state other than:
o Subject Leases with title, consent or pref. right problems
o Subject Leases that have been farmed out entirely
o Subject Leases that pertain exclusively to the Rome Exploration Area
in Kentucky
Exhibit A Page 1
<PAGE> 25
EXHIBIT A-1
DESIGNATED WELLS
With respect to the Conveyance for each of Kentucky and West Virginia this
Exhibit A-1 will include a description of each of the 2471 "Designated Wells"
situated in such state.
Exhibit A-1 Page 1
<PAGE> 26
EXHIBIT B-1
EXCLUDED WELLS
With respect to the Conveyance for each of Kentucky and West Virginia this
Exhibit B will include a description of each of the "Excluded Wells" situated on
the "Subject Leases" in such state, the Excluded Wells include:
o Section 29 Wells
o Wells drilled in the last [21] months
o low volume Wells
o non operated Wells
o Wells with title, consent or pref. Right problem
Exhibit B-1 Page 1
<PAGE> 27
EXHIBIT B-2
FARMOUT AGREEMENTS
Exhibit B-2 Page 1
<PAGE> 28
EXHIBIT C
Attached to and made a part of that certain Net Overriding Royalty Conveyance
(Appalachian Natural Gas Trust) dated effective September 1, 1999 (the
"Conveyance")
ACCOUNTING PROCEDURE
I. GENERAL PROVISIONS
1. DEFINITIONS
"G and C Fees" shall mean the gathering and compression fees charged by the
Assignor in accordance with Article III. "Personal Expenses" shall mean
travel and other reasonable reimbursable expenses. "Material" shall mean
personal property, equipment or supplies acquired or held for use for the
benefit of the Subject Interests. All other capitalized terms shall have the
meanings set forth in the Conveyance.
2. APPLICATION OF AGREEMENT
This Accounting Procedure will apply whether or not Assignor or any
Affiliate of Assignor is the operator of the applicable Subject Interests.
3. CONFLICTS
In the event there exists any conflict between the terms of this Accounting
Procedure or any Accounting Procedure that applies to the Subject Interests
and the Conveyance to which it is attached, the Conveyance will control.
II. DIRECT CHARGES
Assignor shall charge the following items as Deductible Costs, which are not
included in the overhead fees and rates described in Article IV:
1. ENVIRONMENTAL
Costs incurred in connection with the ownership or operation of the Subject
Interests as a result of governmental or regulatory requirements to satisfy
environmental considerations applicable to the Subject Interests and other
costs and expenses to comply with applicable laws related to health, safety
or the environment. Such costs may include pollution control procedures as
required by applicable laws and regulations or other remedial measures
necessary for the protection of the environment, and any costs related to
employees of Assignor performing any environmental work involving the
Subject Interests.
Exhibit C Page 1
<PAGE> 29
2. BONUSES, RENTALS AND ROYALTIES
Lease bonuses, rentals and royalties paid by Assignor attributable to the
Subject Interests.
3. MATERIAL
Material purchased, rented or furnished by Assignor in connection with
drilling, reworking, recompletion (including "behind pipe" completions), and
abandonment of wells on the Subject Lands. Only such Material shall be
purchased for or transferred to the Subject Lands as may be required for
immediate use and is reasonably practical and consistent with efficient and
economical operations. Surplus stocks of Material may be accumulated.
4. TRANSPORTATION
Transportation and/or storage of Material necessary for operations
pertaining to the Subject Interests.
5. SERVICES
The cost of contract services, equipment and utilities provided by outside
sources, except services excluded by Paragraph 8 of Article II. The cost of
professional consultant services and contract services of technical
personnel not an employee of Assignor and directly engaged in connection
with the Subject Interests.
6. EQUIPMENT AND FACILITIES
A. Assignor shall charge as a Deductible Cost for use of equipment and
facilities owned by Assignor or any of its Affiliates at rates commensurate
with costs of ownership and operation including, but not limited to, meters,
compressors, dehydration units, tanks and pipelines. Such rates shall
include costs of maintenance, repairs, other operating expense, insurance,
taxes, depreciation, and return on gross investment less accumulated
depreciation not to exceed twenty-five percent (25%) per annum.
B. This Paragraph 6 shall not affect any current charges made by Assignor
related to G and C Fees or related charges by an Affiliate of Assignor.
Exhibit C Page 2
<PAGE> 30
7. DAMAGES AND LOSSES TO JOINT PROPERTY
All costs or expenses necessary for the repair or replacement of equipment,
Material, fixtures or other property used or held for use in connection with
the Subject Interests made necessary because of damages or losses incurred
by fire, flood, storm, theft, accident, or other cause, except those
resulting from Assignor's gross negligence or willful misconduct.
8. LEGAL EXPENSE
Expense of handling, investigating and settling litigation or claims,
discharging of liens, payment of judgments and amounts paid for settlement
of claims incurred in or resulting from operations under the Conveyance or
necessary to protect or recover the Subject Interests, and the costs and
expenses incurred in connection with hearings and other matters before
governmental bodies and agencies and costs and expenses incurred in curing
title to the Subject Interests. Costs incurred by Assignor in procuring
abstracts and fees paid to outside attorneys for title examination
(including preliminary, supplemental, shut-in gas royalty opinions and
division order title opinions) shall be included as a Deductible Cost.
Assignor shall make no charge for services rendered by its staff attorneys
or other employed personnel in the performance of the above functions.
9. TAXES
All taxes of every kind and nature assessed or levied upon or in connection
with the Subject Interests, the operation thereof, or the production
therefrom, and which taxes have been paid by the Assignor for the benefit of
the Assignor or Assignee. Assignor may make a Tax Accrual, as defined in the
Conveyance.
10. PLUGGING, ABANDONMENT AND RECLAMATION
Costs incurred for abandonment and reclamation relating to the Subject
Interests, including costs required by governmental or other regulatory
authority.
11. OTHER EXPENDITURES
Any other expenditure not covered or dealt with in the foregoing provisions
of this Article II, or Article III, or Article IV and which is of direct
benefit to the Subject Interests and is incurred by the Assignor in the
necessary and proper conduct of operations pertaining to the Subject
Interests. The failure to list certain direct charges under this Article II
shall not prohibit the inclusion of such amounts as Deductible Costs to the
extent provided for under Section 2.01 of the Conveyance.
Exhibit C Page 3
<PAGE> 31
III. GATHERING AND COMPRESSION FEES
As compensation for gathering and compression charges, Assignor shall charge as
a Deductible Cost for all costs and expenses related to the measurement,
gathering, compression, processing and dehydration of Subject Hydrocarbons
attributable to the Subject Interests, including, but not limited to, the cost
of equipment, an overhead and handling charge, a return on gross investment less
accumulated depreciation not to exceed twenty-five percent (25%), repairs,
supplies, fuel (including line loss and unaccounted-for gas), Materials, rental
fees, taxes, rights-of-way and other acquisition costs, personnel costs
(including Personal Expenses and employee benefits), and depreciation on
investment. The G&C Fees shall be adjusted annually as of the first day of April
each year beginning on April 1, 2001 and applied to production beginning on
April 1st of each calendar year. The adjustment shall be computed by Assignor by
calculating its actual gathering and compression costs together with a return on
gross investment less accumulated depreciation, as described in this Article
III, for the preceding calendar year.
IV. OVERHEAD
1. DRILLING OVERHEAD FEE AND PRODUCING OPERATIONS
A. As compensation for administrative, supervision, and office
services, Assignor shall charge drilling and producing operations
on a Fixed Rate Basis in accordance with Article IV.1.C. Such
charge shall be in lieu of costs and expenses of all offices and
salaries or wages plus applicable burdens and expenses of all
personnel, except those costs and expenses related to G and C
Fees, as more fully described under Article III, or those directly
chargeable in connection with the Subject Interests under Article
II. The cost and expense of services from outside sources
(including consultants) in connection with matters of taxation,
geological, engineering, land, accounting or matters before or
involving governmental agencies shall not be considered as
included in the overhead rates, described in Article IV.1.C.
B. The Personal Expenses in connection with the provision of
professional consultant services and contract services of
technical personnel directly employed on the Joint Property shall
not be covered by the overhead rates, described in Article IV.1.C.
C. Overhead - Fixed Rate Basis
1. Assignor shall charge as a Deductible Cost the following rates and
fees per well:
(a) Drilling Overhead Fee: $36,000 per well for all wells drilled
on or attributable to the Subject Interests for which drilling
is commenced on or after the Effective Date and all wells that
are deepened to another zone or horizon on or after the
Effective Date.
Exhibit C Page 4
<PAGE> 32
(b) Producing Well Fixed Fees:
(i) Producing Well Fixed Fee: $170 per well per month for
wells completed at or above a subsurface depth of 7,000
feet and producing five (5) or more mcfe per day,
measured on an annualized basis for the preceding
calendar year, determined on the first day of January of
each year; provided, that if such well was not producing
during such preceding calendar year then measured on a
monthly basis for the preceding month, or
(ii) Producing Well Fixed Fee: $70 per well per month for
wells completed at or above a subsurface depth of 7,000
feet and producing less than five (5) mcfe per day,
measured on an annualized basis for the preceding
calendar year; provided, that if such well was not
producing during such preceding calendar year then
measured on a monthly basis for the preceding month, or
(iii) Deep Producing Well Fixed Fee: $300 per well per month
for wells completed below a depth of 7,000 feet.
(c) Overhead Rate: $65 per well per month for fixed overhead
costs, in addition to the Drilling Overhead Fee and the
Producing Well Fixed Fee described above.
2. Application of Overhead - Fixed Rate Basis shall be as follows:
(a) Drilling Overhead Fee
(i) Drilling Overhead Fee shall be charged for each well
that is drilled on or attributable to the Subject Lands,
whether such well is suspended, completed or abandoned.
(ii) Drilling Overhead Fee shall be charged for each well
located on or attributable to the Subject Interests that
is deepened to another zone or horizon, whether such
deepening operation results in additional production.
(b) Producing Well Fixed Fees and Overhead Rates
(i) An active well either produced or injected into for any
portion of the month shall be considered as a one-well
charge for the entire month.
(ii) Each active completion in a multi-completed well in
which production is not commingled down hole shall be
considered as a
Exhibit C Page 5
<PAGE> 33
one-well charge for each such completion. Each active
completion in a multi-completed well in which production
is commingled down hole shall be considered as a
one-well charge for the entire well.
(iii) The applicable Producing Well Fixed Fee and Overhead
Rate shall apply to all shut in wells, temporarily
abandoned wells and other inactive wells that have not
been plugged and abandoned.
(iv) A one-well charge shall be made for the month in which
plugging and abandonment operations are completed on a
well. This one-well charge shall be made whether or not
the well has produced.
(v) If a multicompleted well in which production is
commingled down hole is completed both above and below
7,000 feet, the Deep Producing Well Fixed Fee shall be
charged with respect to such well rather than either of
Producing Well Fixed Fees described in Article
IV.1.C.1.(b)(i) or Article IV.1.C.1.(b)(ii) above.
3. The Drilling Overhead Fee, Producing Well Fixed Fee, and the
Overhead Rate shall be adjusted annually as of the first day of
April each year beginning on April 1, 2001. The adjustment shall
be computed by multiplying the rate indicated by the Percentage
increase or decrease in the average weekly earnings of Crude
Petroleum and Gas Production Workers for the last calendar Year
compared to the calendar year preceding as shown by the index of
average weekly earnings of Crude Petroleum and Gas Production
Workers as published by the United States Department of Labor,
Bureau of Labor Statistics. The adjusted rates shall be the rates
currently in use, plus or minus the computed adjustment.
Exhibit C Page 6
<PAGE> 1
EXHIBIT 10.6
GAS PURCHASE AGREEMENT
THIS AGREEMENT, entered into this first day of November, 1997,
("Effective Date") by and between EASTERN STATES OIL & GAS, INC., a Virginia
corporation ("Seller"), and CNG ENERGY SERVICES CORPORATION, a Delaware
corporation ("Buyer").
WHEREAS, Seller has available a supply of natural gas at certain points
of connection on the pipeline system identified in Exhibit B, which are for
sale; and
WHEREAS, Buyer is seeking to purchase gas supplies; and
NOW THEREFORE, in consideration of the premises and mutual covenants
herein contained, Seller and Buyer hereby mutually agree as follows:
ARTICLE I
DEFINITIONS
1.1 The term "Agreement" shall mean this Firm Gas Purchase Agreement
and the Confirmation(s) attached hereto as executed from time to time and made a
part hereof.
1.2 The term "Confirmation" shall mean the letter agreement, a form
copy of which is attached hereto as Exhibit "A", which may be executed by Buyer
and Seller from time to time and which shall bind Buyer and Seller to particular
transactions for the purchase and sale of the gas in accordance with the terms
thereof and this Agreement.
1.3 The term "Day" shall mean the twenty-four (24) hour period
commencing at eight o'clock (8:00) a.m. Eastern Time.
1.4 The term "Dth" shall mean the quantity of heat energy which is one
million British Thermal Units (MMBtu).
1.5 The term "Effective Period" shall mean the period of time (Days,
Months, or any portion thereof) specified on the then effective Confirmation.
1.6 The term "Gas" shall mean natural gas or any mixture of
hydrocarbons or of hydrocarbons and noncombustible gases, in a gaseous state.
1.7 The term "Mcf" shall mean one thousand (1,000) cubic feet of gas
measured at the temperature and pressure specified by the System identified in
Exhibit "B."
1.8 The term "Quantity" shall mean the amount of Gas set forth in the
Confirmation which Buyer agrees to purchase and receive pursuant to the terms
and conditions hereof at the Delivery Point(s) as defined in Article IV herein.
<PAGE> 2
1.9 The term "System" shall mean the pipeline system of an interstate
pipeline or local distribution company as identified on the applicable
Confirmation.
ARTICLE II
NATURE OF SERVICE
2.1 For all deliveries and receipts of gas hereunder, the obligations
of the parties shall be firm and subject to suspension only for the duration of
an event of Force Majeure, as defined herein. A non-performing party shall be
responsible for payment of those costs reasonably incurred by the performing
party, including incremental transportation costs, in securing alternate supply
(where Buyer is the performing party) or alternate market (where Seller is the
performing party).
ARTICLE III
CONFIRMATION
3.1 Buyer agrees to purchase the Quantity of Gas from Seller for the
Price at the Delivery Point(s) for the Effective Period. The Quantity, Price,
Delivery Point(s), Effective Period and other special provisions shall be
identified in the Confirmation.
3.2 Buyer and Seller agree that the specific terms associated with
Price, Quantity, Delivery Point(s), Effective Period and other special
provisions are subject to change from time to time upon mutual agreement of the
parties hereto by written execution of a "Confirmation" substantially in the
form of Exhibit "A".
3.3 The parties hereby consent to the tape recording of telephone
conversations in which agreement to a Transaction is reached. Any such tape
recording will be deemed a "writing" and "signed" by the parties and may be
introduced as evidence to prove the fact or terms of a Transaction.
ARTICLE IV
DELIVERY POINT(s)
4.1 The "Delivery Point(s)", as listed in an effective Confirmation,
are the points at which delivery of the Gas purchased herein are deemed to be
made at a point of the interconnection of Seller's gathering facilities with the
metering facilities of the System identified on Exhibit "B." Seller shall
arrange and be responsible for the delivery of the Gas to the Delivery Point(s)
as specified on the then effective Confirmation. Buyer shall arrange and be
responsible for the transportation of the Gas after delivery is made at the
Delivery Point(s).
2
<PAGE> 3
ARTICLE V
PRICE
5.1 The price ("Price") paid by Buyer during each Effective Period, for
the Gas delivered by Seller to the Delivery Point(s), shall be as specified on
the then effective Confirmation(s). The price is inclusive of all production,
severance, excise, ad valorem, royalties or similar taxes levied on the
production or transportation of the Gas prior to or at its delivery to Buyer
hereunder.
ARTICLE VI
TERM
6.1 The Agreement shall become effective on the Effective Date hereof
and shall remain in full force and effect for one year from the Effective Date
and thereafter until terminated by either party upon thirty (30) days' written
notice to the other party; however, in the event either party terminates this
Agreement during an Effective Period of a Confirmation, this Agreement shall
survive until the expiration of such Effective Period and the satisfaction of
all obligations thereunder.
ARTICLE VII
BILLING AND PAYMENT
7.1 Seller shall deliver to Buyer an invoice, including the delivery
statement provided by the System identified on Exhibit "B." By the fifty-fifth
(55th) day following deliveries, Buyer shall pay Seller for such deliveries. In
the event a dispute arises as to the amount payable in any invoice rendered
hereunder, Buyer shall nevertheless pay when due the amount not in dispute under
such invoice. Such payment shall not be deemed to be a waiver of the right by
Buyer to recoup any overpayment, nor shall acceptance of any payment be deemed
to be a waiver by Seller of any underpayment. In the event that a System issues
a prior period adjustment as to amounts delivered to Buyer, such adjustment
shall be invoiced or credited to Buyer's account at the price as of the month of
delivery.
7.2 In the event Buyer fails to forward the entire amount due, except
amounts disputed in good faith, to Seller when same is due, interest on the
unpaid portion shall accrue at a rate equal to one percent (1%) above the prime
rate charged by Chase Manhattan Bank, New York, from time to time, or the
maximum legal rate, whichever is the lesser, compounded daily from the date such
payment is due until the same is paid.
7.3 Each party hereto shall have the right at all reasonable times to
examine the books and records of the other party to the extent necessary to
verify the accuracy of any statement, charge, computation, invoice or demand
made under or pursuant to this Agreement. Any payment shall be final as to both
parties unless questioned within twelve (12) calendar months from the date of
such payment.
3
<PAGE> 4
ARTICLE VIII
MEASUREMENT AND QUALITY OF GAS
8.1 Quantities of Gas delivered to the Delivery Point(s) hereunder
shall be measured according to the measurement provisions contained in the
tariff of the applicable System.
8.2 On the 20th day of the month immediately preceding delivery, Seller
shall provide Buyer with estimates of volumes of Gas to be delivered and shall
update this as necessary prior to the close of the New York Mercantile Exchange
final settlement day. The parties agree that deliveries up to five percent (5%)
above or below the estimated volumes shall be acceptable and shall not be
subject to imbalance or other penalties.
8.3 Seller shall deliver Gas which meets the applicable System's
required quality specifications.
ARTICLE IX
TITLE AND WARRANTY OF TITLE
9.1 Except as provided by Section 4.1, title to and risk of loss of all
Gas delivered hereunder shall pass and vest in Buyer at the Delivery Point(s).
9.2 Seller warrants the title to the Gas delivered hereunder, that it
has good and lawful authority to sell such Gas, and that such Gas is free from
all liens and adverse claims of any kind or character. Seller agrees to
indemnify and hold Buyer harmless from all claims, suits, actions, debts,
accounts, damages, costs, losses and expenses of every kind and character
arising out of any adverse claim to or against such title. In the event an
adverse claim is brought against Gas which is subject to this Agreement, Buyer
may suspend payment for such Gas pending resolution of that claim.
ARTICLE X
FORCE MAJEURE
10.1 If, by reason of Force Majeure, either party is rendered unable,
wholly or in part, to carry out its obligations under this Agreement, such party
shall be excused from performance hereunder, except to the extent payment is due
for Gas delivered, during the continuance of any inability so caused. "Force
Majeure" shall mean acts of God; strikes, lockouts or industrial disturbances;
interruptions by government or court orders, present or future orders of any
regulatory body having jurisdiction; acts of the public enemy; wars; riots;
inability to secure materials or labor; inability to secure right-of-way;
epidemics, landslides; lightning; earthquakes; fires; storms; floods;
explosions; breakage or accident to machinery, pipelines, compressors or
equipment; unplanned outages of compressor equipment or pipelines; freezing of
wells or pipelines; or any other situation, occurrence or condition not
reasonably within the control of the party claiming suspension, including,
without limitation, interruption of firm transportation, gathering, treating,
compression or services required of third parties. In the event either party is
unable to perform its obligations
4
<PAGE> 5
hereunder due to Force Majeure as defined herein, that party shall notify the
other party as soon as practicable and shall use due diligence to alleviate such
condition(s).
ARTICLE XI
TAXES
11.1 Seller shall pay, or cause to be paid, all royalties, overriding
royalties and payments out of production and all taxes including, without
limitation, severance and production taxes, imposed on or with respect to the
gas prior to or at its delivery at the Delivery Point; provided, however, if
state law requires Buyer to remit such taxes to the collecting authority, Buyer
shall do so and deduct the taxes so paid from payments otherwise due hereunder.
ARTICLE XII
MISCELLANEOUS
12.1 Notice. Any notice, request, or statement ("Notice") provided in
this Agreement between Buyer and Seller shall be in writing. Such Notice may be
transmitted via ordinary mail or telecopy.
Any such Notice shall be considered as duly delivered as of the earlier
of the receipt date indicated on the telecopy or the postmark date when mailed
by ordinary mail to the other party at the following address:
(a) NOTICE TO SELLER:
Attn: Contract Administration
Eastern States Oil and Gas, Inc.
1710 Pennsylvania Ave.
Charleston, WV 25302
Telecopy: 304-344-0363
Telephone: 304-343-9566
(b) PAYMENT TO SELLER:
Eastern States Oil & Gas, Inc.
ABA: 043-000-096
5
<PAGE> 6
Acct: 0245-1315
PNC Bank
Pittsburgh, PA 15264
Telecopy:
Telephone:
(c) NOTICE TO BUYER:
Attn: Contract Administration
CNG ENERGY SERVICES CORPORATION
One Park Ridge Center
P.O. Box 15746
Pittsburgh, PA 15244-0746
Telecopy: (412) 787-4464
Telephone: (412) 787-4000
(d) STATEMENT TO BUYER:
Attn: Gas Accounting
CNG Energy Services Corporation
One Park Ridge Center
P.O. Box 15746
Pittsburgh, PA 15244-0746
Telecopy: (412) 787-4027
Telephone: (412) 787-4000
12.2 Entire Agreement and Amendments. This written Agreement, including
the then effective Confirmation(s), contains the entire Agreement between the
parties and there are no other understandings or representations between the
parties hereto. This Agreement may not be amended except by an instrument in
writing.
12.3 Governing Law. This Agreement shall be governed and construed in
accordance with the substantive laws of the state of Pennsylvania, without
regard to the choice of law rules thereof.
12.4 Severability. If any provision of this Agreement shall be held
invalid, illegal, or unenforceable to any extent and for any reason by a court
of competent jurisdiction, the remainder of this Agreement shall not be affected
thereby and shall be enforceable to the full extent permitted by law.
6
<PAGE> 7
12.5 Waiver. The failure of either party at any time to exercise any
right or to require performance by the other party of any provision herein shall
in no way affect the right of such party thereafter to enforce the same, nor
shall the waiver by either party hereto of any breach of any provision herein by
the other party be a waiver of any other breach of such provision, or as a
waiver of the provision itself.
12.6 Headings. The title headings are for identification and reference
only and shall not be used in interpreting any part of this Agreement.
12.7 Joint Efforts. This Agreement shall be considered for all purposes
as prepared through the joint efforts of the parties, and shall not be construed
against one party or the other as a result of the preparation, submittal or
other event of negotiation drafting or execution thereof.
12.8 Assignment. This Agreement shall inure to and be binding upon the
successors and assigns of the parties hereto; provided, that neither party shall
assign this Agreement and the rights hereunder without first having obtained the
written approval of the other party which approval shall not be unreasonably
withheld.
IN WITNESS WHEREOF, the parties have duly executed this Agreement
effective as of the day and year first above written.
CNG ENERGY SERVICES CORPORATION
By: /s/ Rita Nagle
--------------------------------------
Name: Rita Nagle
Title:
EASTERN STATES OIL & GAS, INC.
By: /s/ Stevens V. Gillespie
--------------------------------------
Name: Stevens V. Gillespie
Title: Senior Vice President
7
<PAGE> 8
CNG FIELD SERVICES COMPANY
CONFIRMATION LETTER
================================================================================
SELLER: BLAZER ENERGY CORPORATION BUYER: CNG FIELD SERVICES COMPANY
2900 EISENHOWER AVENUE 140 WEST MAIN STREET
SUITE 300 P.O. BOX 1570
ALEXANDRIA, VA 22314 CLARKSBURG, WV 26302-1570
ATTN: Stevens V. Gillespie ATTN: Tony Garcia
(703) 317-2327 (304) 623-8168
FAX #: (703) 317-2304 FAX #: (304) 623-8973
================================================================================
Quantity: 11/01/98 to 01/31/99 24,275 MMBtu Daily (Estimated)
02/01/99 to 10/31/99 29,275 MMBtu Daily (Estimated)
- --------------------------------------------------------------------------------
Type of Service: FIRM
Seller shall be required to sell and Buyer shall be required to purchase the
quantities of Gas set forth herein. Either party may interrupt its performance
only to the extent that such performance is prevented for reasons of Force
Majeure or curtailment of firm transportation and/or storage, without liability
to the other party. If a party interrupts for any other reason or curtails a
Firm customer before curtailing similarly affected Interruptible customers, the
non-breaching party's exclusive remedy shall be that it may recover its Cover
Costs.
- --------------------------------------------------------------------------------
Term: 11/1/98 through 10/31/99
- --------------------------------------------------------------------------------
Price: 11/01/98 to 03/31/99 @IF-CNGApp plus $0.04 USD Per MMBtu
(Base) (Reference)
04/01/99 to 10/31/99 @IF-CNGApp plus $0.01 USD Per MMBtu
(Base) (Reference)
- --------------------------------------------------------------------------------
Delivery Point: CNG TRANSMISSION CORPORATION @ HASTINGS GATHERING POOLS
CNG TRANSMISSION CORPORATION @ HASTINGS TRANSMISSION POOLS
CNG TRANSMISSION CORPORATION @ CORNWELL GATHERING POOLS
CNG TRANSMISSION CORPORATION @ CORNWELL TRANSMISSION POOLS
CNG TRANSMISSION CORPORATION @ BRIDGEPORT GATHERING POOLS
CNG TRANSMISSION CORPORATION @ HASTINGS TRANSMISSION POOLS
CNG TRANSMISSION CORPORATION @ MISCELLANEOUS TRANSMISSION POOLS
- --------------------------------------------------------------------------------
Pipeline: CNG TRANSMISSION CORPORATION
- --------------------------------------------------------------------------------
Special Provisions: LESS APPLICABLE GATHERING AND EXTRACTION FEES, BASED ON
ACTUAL VOLUMES CREDITED TO FSC POOL WITHIN 5% OF SELLER ESTIMATE.
- --------------------------------------------------------------------------------
This purchase is subject to the existing contract between Buyer and Seller.
================================================================================
By: CNG FIELD SERVICES COMPANY
/s/ Tony Garcia
BUYER --------------------------------------------------
Title: Manager--Appalachian Supply Date: 10/16/98
- --------------------------------------------------------------------------------
By: EASTERN STATES OIL & GAS, INC.
SELLER /s/ Stevens V. Gillespie
--------------------------------------------------
Title: Senior Vice President Date: 10/18/98
================================================================================
PLEASE EXECUTE AND RETURN BY FAX ASAP TO (304) 623-8973
This confirmation letter will be deemed accepted if no
response is received within two (2) days.
<PAGE> 9
CNG FIELD SERVICES COMPANY
CONFIRMATION LETTER
================================================================================
Deal ID: P-BLAZERENERGY-0004
SELLER: BLAZER ENERGY CORPORATION BUYER: CNG FIELD SERVICES COMPANY
2800 Eisenhower Avenue P.O. Box 1570
Alexandria, VA Clarksburg, WV
United States 22314 United States 26302-1570
ATTN: Gillespie, Steve ATTN: Charles Roberts
PHONE: (703) 317-2300 PHONE #: (304) 623-8167
FAX #: (703) 317-2304 FAX #: (304) 623-8973
================================================================================
TYPE OF SERVICE: Firm
Seller shall be required to sell and Buyer shall be required to purchase the
quantities of Gas set forth herein. Either party may interrupt its performance
only to the extent that such performance is prevented for reasons of Force
Majeure or curtailment of firm transportation and/or storage, without liability
to the other party. If a party interrupts for any other reason or curtails a
Firm customer before curtailing similarly affected Interruptible customers, the
non-breaching party's exclusive remedy shall be that it may recover its Cover
Costs.
- --------------------------------------------------------------------------------
TERM: 11/01/1998 through 10/31/99
- --------------------------------------------------------------------------------
DELIVERY POINT:
11/01/1998 to 10/31/1999: CNG Transmission Corporation @ GWFS -
GATHERING WET - FS POOL
- --------------------------------------------------------------------------------
PRICE:
DEAL PRICES
11/01/1998 to 10/31/1999:
Purchase Gas @ Inside Ferc CNGT Appalachia USD Per MMBtu (Base) (Reference)
OTHER COSTS
11/01/1998 to 10/31/1999:
Gath/Extract @ Meter: GWFS GATHERING WET - FS POOL @ Appalachian Gathering
Wet Deduct USD Per MMBtu (Quantity)
- --------------------------------------------------------------------------------
QUANTITY:
Effective: 11/01/1998 to 10/31/1999: 6,274 MMBtu Daily
- --------------------------------------------------------------------------------
SPECIAL PROVISIONS: Less applicable gathering and extraction fees
- --------------------------------------------------------------------------------
This purchase is subject to the existing contract between Buyer and Seller.
================================================================================
By: CNG FIELD SERVICES COMPANY
BUYER /s/ Charles Roberts
--------------------------------------------------
Title: Date: 1/13/99
- --------------------------------------------------------------------------------
By:
SELLER /s/ Stevens V. Gillespie
--------------------------------------------------
Title: Senior Vice President Date: 3/16/99
================================================================================
PLEASE EXECUTE AND RETURN BY FAX ASAP TO (304) 623-8973
This confirmation letter will be deemed accepted if no
response is received within two (2) days.
<PAGE> 10
<TABLE>
<CAPTION>
CNG FIELD SERVICES CORPORATION
CONFIRMATION LETTER
===================================================================================================================
<S> <C> <C> <C>
DEAL ID: P-EASTERNSTATE-0005
SELLER: EASTERN STATES OIL & GAS, INC. BUYER: CNG FIELD SERVICES COMPANY
2800 Eisenhower Avenue P.O. Box 1570
Alexandria, VA Clarksburg, WV
United States 22314 United States 26302-1570
ATTN: Gillespie, Steve ATTN: Tony Garcia
PHONE: (703) 317-2300 PHONE #: (304) 623-8168
FAX #: (703) 317-2301 FAX #: (304) 623-8973
===================================================================================================================
</TABLE>
TYPE OF SERVICE: FIRM
Seller shall be required to sell and Buyer shall be required to purchase the
quantities of Gas set forth herein. Either party may interrupt its performance
only to the extent that such performance is prevented for reasons of Force
Majeure or curtailment of firm transportation and/or storage, without liability
to the other party. If a party interrupts for any other reason or curtails a
Firm customer before curtailing similarly affected Interruptible customers, the
non-breaching party's exclusive remedy shall be that it may recover its Cover
Costs.
- --------------------------------------------------------------------------------
TERM: 11/01/1999 through 10/31/2000
- --------------------------------------------------------------------------------
DELIVERY POINT:
11/01/1999 to 10/31/2000: CNG Transmission Corporation @ GDFS - GATHERING DRY -
FS POOL
11/01/1999 to 10/31/2000: CNG Transmission Corporation @ GWFS - GATHERING WET -
FS POOL
11/01/1999 to 10/31/2000: CNG Transmission Corporation @ TWFS - TRANSMISSION
WET - FS POOL
- --------------------------------------------------------------------------------
PRICE:
DEAL PRICES
11/01/1999 to 10/31/2000: Purchase Gas @ Inside Ferc CNGT Appalachia Increment:
$0.02 USD Per MMBtu (Base)(Reference)
OTHER COSTS
11/01/1999 to 10/31/2000: Extraction @ Meter: TWFS TRANSMISSION WET - FS POOL
@ Appalachian Transmission Wet Deduct USD Per MMBtu (Quantity)
11/01/1999 to 10/31/2000: Gath/Extract @ Meter: GWFS GATHERING WET - FS POOL @
Appalachian Gathering Wet Deduct USD Per MMBtu (Quantity)
11/01/1999 to 10/31/2000: Gathering @ Meter: GDFS GATHERING DRY - FS POOL @
Appalachian Gathering Dry Deduct USD Per MMBtu (Quantity)
- --------------------------------------------------------------------------------
QUANTITY:
Effective: 11/01/1999 to 10/31/2000: 24,000 MMBtu Daily
- --------------------------------------------------------------------------------
SPECIAL PROVISIONS: Less applicable gathering and extraction fees
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
This purchase is subject to the existing contract between Buyer and Seller.
===================================================================================================================
<S> <C> <C>
BUYER CNG FIELD SERVICES COMPANY:
/s/ Tony Garcia
----------------------------------------------------------------------------------------
Title: Manager, Appalachian Supply Date:
- -------------------------------------------------------------------------------------------------------------------
SELLER By: /s/ Stevens V. Gillespie
----------------------------------------------------------------------------------------
Title: Senior Vice President Date:
===================================================================================================================
</TABLE>
PLEASE EXECUTE AND RETURN BY FAX ASAP TO (304) 623-8973.
This confirmation letter will be deemed accepted if no
response is received within two (2) days.
<PAGE> 1
EXHIBIT 10.7
GAS PURCHASE AGREEMENT
THIS AGREEMENT entered into this first day of August 1998, ("Effective
Date") by and between STATOIL ENERGY, INC. a Virginia corporation ("Seller"),
and CNG Producing Company, a Delaware corporation ("Buyer").
WHEREAS, Seller has available a supply of natural gas at certain points
of connection on the pipeline system identified in Exhibit A, which are for
sale; and
WHEREAS, Buyer is seeking to purchase gas supplies; and
NOW THEREFORE, in consideration of the premises and mutual covenants
herein contained, Seller and Buyer hereby mutually agree as follows:
ARTICLE I
DEFINITIONS
1.1 The term "Agreement" shall mean this Gas Purchase Agreement and the
Confirmation(s) attached hereto as executed from time to time and made a part
hereof.
1.2 The term "Confirmation" shall mean the letter agreement, a form
copy of which is attached hereto as Exhibit "A", which may be executed by Buyer
and Seller from time to time and which shall bind Buyer and Seller to particular
transactions for the purchase and sale of the gas in accordance with the terms
thereof and this Agreement.
1.3 The term "Day" shall mean the twenty-four (24) hour period
commencing at eight o'clock (8:00) a.m. Eastern Time.
1.4 The term "Dth" shall mean the quantity of heat energy which is one
million British Thermal Units (MMBtu).
1.5 The term "Effective Period" shall mean the period of time (Days,
Months, or any portion thereof) specified on the then effective Confirmation.
1.6 The term "Gas" shall mean natural gas or any mixture of
hydrocarbons or of hydrocarbons and noncombustible gases, in a gaseous state.
1.7 The term "Mcf" shall mean one thousand (1,000) cubic feet of gas
measured at the temperature and pressure specified on Buyer's gathering system
set forth herein.
1.8 The term "Quantity" shall mean the amount of Gas set forth in the
Confirmation which Buyer agrees to purchase and receive pursuant to the terms
and conditions hereof at the Delivery Point(s) as defined in Article IV herein.
<PAGE> 2
1.9 The term "Gathering System" shall mean CNG Transmission's
Appalachian gathering system.
ARTICLE II
NATURE OF SERVICE
2.1 For all deliveries and receipts of gas hereunder, the obligations
of the parties shall be firm and subject to suspension only for the duration of
an event of Force Majeure. A non-performing party shall be responsible for
payment of those costs reasonably incurred by the performing party, including
incremental transportation costs, in securing alternate supply (where Buyer is
the performing party) or alternate market (where Seller is the performing
party). However, a non-performing party shall not be required to pay
consequential damages.
ARTICLE III
CONFIRMATION
3.1 Buyer agrees to purchase the Quantity from Seller for the Price at
the Delivery Point(s) for the Effective Period. The Quantity, Price, Delivery
Point(s), Effective Period and other special provisions shall be identified in
the Confirmation.
3.2 Buyer and Seller agree that the specific terms associated with
Price, Quantity, Delivery Point(s), Effective Period and other special
provisions are subject to change from time to time upon mutual agreement of the
parties hereto by written execution of a "Confirmation" substantially in the
form of Exhibit "A".
3.3 The parties hereby consent to the tape recording of telephone
conversations in which agreement to a Transaction is reached. Any such tape
recording will be deemed a "writing" and "signed" by the parties and may be
introduced as evidence to prove the fact or terms of a Transaction.
ARTICLE IV
DELIVERY POINT(S)
4.1 The "Delivery Point(s)", as listed in an effective Confirmation,
are the points at which delivery of the Gas purchased hereunder are deemed to be
made at a point of the interconnection of Seller's gathering facilities with the
metering and Gathering System of CNG Transmission. Seller shall arrange and be
responsible for the delivery of the Gas to the Delivery Point(s) as specified on
the then effective Confirmation. Buyer shall arrange and be responsible for the
transportation of the Gas after delivery is made at the Delivery Point(s).
2
<PAGE> 3
ARTICLE V
PRICE
5.1 The price ("Price") paid by Buyer during each Effective Period, for
the Gas delivered by Seller to the Delivery Point(s), shall be as specified on
the then effective Confirmation(s). The price is inclusive of all production,
sales, severance, excise, ad valorem, royalties or similar taxes levied on the
production or transportation of the Gas prior to or at its delivery to Buyer
hereunder.
ARTICLE VI
TERM
6.1 The Agreement shall become effective on the Effective Date hereof
and shall remain in full force and effect for one year from the Effective Date
and thereafter until terminated by either party upon thirty (30) days' written
notice to the other party; however, in the event either party terminates this
Agreement during an Effective Period of a Confirmation, this Agreement shall
survive until the expiration of such Effective Period and the satisfaction of
all obligations thereunder.
ARTICLE VII
BILLING AND PAYMENT
7.1 Seller shall render an invoice not later than 30 days after the
month of production and Buyer shall pay Seller not later than 60 days after the
month of production. In the event a dispute arises as to the amount payable in
any invoice rendered hereunder, Buyer shall nevertheless pay when due the amount
not in dispute under such invoice. Such payment shall not be deemed to be a
waiver of the right by Buyer to recoup any overpayment, nor shall acceptance of
any payment be deemed to be a waiver by Seller of any right to collect the
unpaid potion of any underpayment.
7.2 In the event Buyer fails to forward the entire amount due, except
amounts disputed in good faith, to Seller when same is due, interest on the
unpaid portion shall accrue at a rate equal to one percent (1%) above the prime
rate charged by Chase Manhattan Bank, New York, from time to time, or the
maximum legal rate, whichever is the lesser, compounded daily from the date such
payment is due until the same is paid.
7.3 Each party hereto shall have the right at all reasonable times to
examine the books and records of the other party to the extent necessary to
verify the accuracy of any statement, charge, computation, invoice or demand
made under or pursuant to this Agreement. Any payment shall be final as to both
parties unless questioned within two (2) years from the date of such payment. In
the event of a pipeline reallocation involving the gas sold hereunder, the
payment shall be considered final two (2) years from the date of such
reallocation.
3
<PAGE> 4
ARTICLE VIII
MEASUREMENT AND QUALITY OF GAS
8.1 Quantities of Gas delivered to the Delivery Point(s) hereunder
shall be measured according to the measurement provisions as contained in the
tariff of CNG Transmission for measuring gas into CNG Transmission's Gathering
System.
8.2 Seller shall deliver Gas which meets the CNG Transmission's quality
specifications for it's Gathering System as contained and updated in CNG
Transmission's FERC Gas Tariff, but in no event less than the following:
a. The Gas delivered shall not contain an amount of water vapor
exceeding the quantity that is required for saturation of the gas at the flowing
temperature and pressure of the gas, whichever is less, provided, however, that
such gas shall not contain any water in its liquid state. Such gas shall not
contain air, nor more than one grain of hydrogen sulfide, 20 grains of total
sulfur per 100 cubic feet, three (3) percent carbon dioxide or a total of five
(5) percent of inert gases. All gas delivered shall be commercial in quality and
be free from any foreign material such as dirt, dust, iron particles and other
similar matter.
b. If the Gas delivered fails to meet the quality specifications
set forth herein, then Buyer may either elect to continue to receive such gas or
refuse to take all or any portion of such gas until the Seller brings the gas
into conformity with such specifications. Such election to continue to receive
nonconforming gas shall not waive Buyer's right to refuse to take nonconforming
gas in the future.
c. Seller shall not install compression or any other mechanical or
accessory equipment to aid in delivery of the gas without first obtaining the
consent of Buyer and CNG Transmission Corporation. Buyer makes no representation
or warranty concerning the pressure which will be maintained in CNG
Transmission's Gathering System from time to time or other conditions which may
affect the quantity of Gas which Seller may be able to deliver to Buyer.
d. Buyer may require Seller to reduce its flow of gas ratably, by
rotational shut-in or complete shut-in of Seller's wells for excessive pressure
on CNG Transmission's Gathering System or maintenance or repair of lines,
equipment, compressors or other facilities essential to the operation of CNG
Transmission's Gathering System.
e. Seller shall not process or cause the processing of any gas
delivered hereunder prior to the point of delivery, for the extraction of
ethane, propane, butane, pentane or other heavier hydrocarbons without first
obtaining the express written authorization of Buyer.
4
<PAGE> 5
ARTICLE IX
TITLE AND WARRANTY OF TITLE
9.1 Except as provided by Section 4.1, title to and risk of loss of all
Gas delivered hereunder shall pass and vest in Buyer at the Delivery Point(s).
9.2 Seller warrants the title to the Gas delivered hereunder, that it
has good and lawful authority to sell such Gas, and that such Gas is free from
all liens and adverse claims of any kind or character. Seller agrees to defend,
indemnify and hold Buyer harmless from all claims, suits, actions, debts,
accounts, damages, costs, losses and expenses of every kind and character
arising out of any adverse claim to or against such title. In the event an
adverse claim is brought against Gas which is subject to this Agreement, Buyer
may suspend payment for such Gas pending resolution of that claim.
ARTICLE X
FORCE MAJEURE
10.1 If, by reason of Force Majeure, either party is rendered unable,
wholly or in part, to carry out its obligations under this Agreement, such party
shall be excused from performance hereunder, except to the extent payment is due
for Gas delivered, during the continuance of any inability so caused. "Force
Majeure" shall mean acts of God, strikes, lockouts or industrial disturbances,
interruptions by government or court orders, present or future orders of any
regulatory body having jurisdiction, acts of the public enemy, wars, riots,
inability to secure materials or labor, inability to secure right-of-way,
epidemics, landslides, lightning, earthquakes, fires, storms, floods,
explosions, breakage or accident to machinery, pipelines, and equipment, loss of
Buyer's principal resale market or any other situation, occurrence or condition
not reasonably within the control of the party claiming suspension. In the event
either party is unable to perform its obligations hereunder due to Force Majeure
as defined herein, that party shall notify the other party as soon as
practicable and shall use due diligence to remedy such condition(s).
ARTICLE XI
TAXES
11.1 Seller shall pay, or cause to be paid, all royalties, overriding
royalties and payments out of production and all taxes including, without
limitation, sales, severance and production taxes, imposed on or with respect to
the gas prior to or at its delivery at the Delivery Point; provided, however, if
state law requires Buyer to remit such taxes to the collecting authority, Buyer
shall do so and deduct the taxes so paid from payments otherwise due hereunder.
5
<PAGE> 6
ARTICLE XII
MISCELLANEOUS
12.1 Notice. Any notice, request, or statement ("Notice") provided in
this Agreement between Buyer and Seller shall be in writing. Such Notice may be
transmitted via ordinary mail or telecopy.
Any such Notice shall be considered as duly delivered as of the earlier
of the receipt date indicated on the telecopy or the postmark date when mailed
by ordinary mail to the other party at the following address:
(a) NOTICE TO SELLER:
Attn: Statoil Energy
Contract Administration
1710 Pennsylvania Ave.
Charleston, WV 25302
Telecopy: 304-344-0363
Telephone: 304-343-9566
(b) PAYMENT TO SELLER:
Eastern States Oil & Gas, Inc.
ABA: 043-000-096
Acct: 0245-1315
PNC Bank
Pittsburgh, PA 15264
(c) NOTICE TO BUYER:
Attn: CNG Producing Company
Attn: Mr. Dennis G. Millet
16945 Northchase Drive
Suite 1750
Houston, TX 77060-2133
6
<PAGE> 7
Telecopy: (281) 873-1530
Telephone: (281) 873-1575
(d) STATEMENT TO BUYER:
Attn: CNG Producing Company
Attn: Mr. Raymond A. G. Oalmann
1450 Poydras Street
New Orleans, LA 70112
Telecopy: (504) 593-7395
Telephone: (504) 593-7472
12.2 Entire Agreement and Amendments. This written Agreement, including
the then effective Confirmation(s), contains the entire Agreement between the
parties and there are no other understandings or representations between the
parties hereto. This Agreement may not be amended except by an instrument in
writing.
12.3 Governing Law. This Agreement shall be governed and construed in
accordance with the substantive laws of the state of West Virginia, without
regard to the choice of law rules thereof.
12.4 Severability. If any provision of this Agreement shall be held
invalid, illegal, or unenforceable to any extent and for any reason by a court
of competent jurisdiction, the remainder of this Agreement shall not be affected
thereby and shall be enforceable to the full extent permitted by law.
12.5 Waiver. The failure of either party at any time to exercise any
right or to require performance by the other party of any provision herein shall
in no way affect the right of such party thereafter to enforce the same, nor
shall the waiver by either party hereto of any breach of any provision herein by
the other party be a waiver of any other breach of such provision, or as a
waiver of the provision itself.
12.6 Headings. The title headings are for identification and reference
only and shall not be used in interpreting any part of this Agreement.
12.7 Joint Efforts. This Agreement shall be considered for all purposes
as prepared through the joint efforts of the parties, and shall not be construed
against one party or the other as a result of the preparation, submittal or
other event of negotiation drafting or execution thereof.
12.8 Assignment. This Agreement shall inure to and be binding upon the
successors and assigns of the parties hereto; provided, that neither party shall
assign this Agreement and the rights hereunder without first having obtained the
written approval of the other party which approval shall not be unreasonably
withheld.
7
<PAGE> 8
IN WITNESS WHEREOF, the parties have duly executed this Agreement effective as
of the day and year first above written.
CNG PRODUCING COMPANY
By: /s/ Dennis G. Millet
-------------------------------------
Name: Dennis G. Millet
Title: Director, Gas Contracts
STATOIL ENERGY, INC.
By: /s/ Stevens V. Gillespie
-------------------------------------
Name: Stevens V. Gillespie
Title: Senior Vice President
8
<PAGE> 9
CNG PRODUCING COMPANY
CONFIRMATION LETTER
================================================================================
SELLER: STATOIL ENERGY, INC. BUYER: CNG PRODUCING COMPANY
2800 EISENHOWER AVENUE 16945 NORTHCHASE DRIVE
ALEXANDRIA, VA 22314 SUITE 1750
HOUSTON, TX 77060-2133
ATTN: STEVE GILLESPIE ATTN: TINA HARMON
(703) 317-2237 (281) 873-1568
FAX #: (703) 317-2304 FAX #: (281) 873-1530
================================================================================
Quantity: Up to 4,500 dth per day
- --------------------------------------------------------------------------------
Type of Service: Firm
- --------------------------------------------------------------------------------
Term: August 1, 1998 through July 31, 1999
- --------------------------------------------------------------------------------
Price: CNG Appalachian Inside FERC First of Month Index plus $0.02
- --------------------------------------------------------------------------------
Delivery Point: Cornwell Transmission Pool
- --------------------------------------------------------------------------------
Pipeline: CNGT
- --------------------------------------------------------------------------------
Special Provisions:
- --------------------------------------------------------------------------------
This purchase is subject to the existing contract between Buyer and Seller.
================================================================================
By: CNG PRODUCING COMPANY
BUYER /s/ Dennis G. Miller
--------------------------------------------------
Title: Director, Gas Contracts Date: 7/30/98
- --------------------------------------------------------------------------------
By: STATOIL ENERGY, INC.
SELLER /s/ Stevens V. Gillespie
--------------------------------------------------
Title: Senior Vice President Date: 8/4/98
================================================================================
PLEASE EXECUTE AND RETURN BY FAX ASAP TO (281)873-1530.
This confirmation letter will be deemed accepted if no response
is received within two (2) days.
<PAGE> 10
<TABLE>
<CAPTION>
CNG PRODUCING COMPANY
CONFIRMATION LETTER
===================================================================================================================
<S> <C> <C> <C>
SELLER: STATOIL ENERGY, INC. BUYER: CNG PRODUCING COMPANY
2800 EISENHOWER AVENUE 16945 NORTHCHASE DRIVE
ALEXANDRIA, VA 22314 SUITE 1750
HOUSTON, TX 77060-2133
ATTN: STEVE GILLESPIE ATTN: TINA HARMON
(703) 317-2237 (281) 873-1568
FAX #: (703) 317-2304 FAX #: (281) 873-1547
===================================================================================================================
Quantity: Up to 10,000 dth per day
- -------------------------------------------------------------------------------------------------------------------
Type of Service: Firm
- -------------------------------------------------------------------------------------------------------------------
Term: November 1, 1998 through October 31, 1999
- -------------------------------------------------------------------------------------------------------------------
Price: CNG Appalachian Inside FERC First of Month Index plus $0.02
- -------------------------------------------------------------------------------------------------------------------
Delivery Point: Cornwell Transmission Pool
- -------------------------------------------------------------------------------------------------------------------
Pipeline: CNGT
- -------------------------------------------------------------------------------------------------------------------
Special Provisions:
- -------------------------------------------------------------------------------------------------------------------
This purchase is subject to the existing contract between Buyer and Seller.
===================================================================================================================
BUYER By: CNG PRODUCING COMPANY
/s/ Tina Harmon
-------------------------------------------------------------------------------------
Title: Date:
Gas Marketer 11/9/98
- -------------------------------------------------------------------------------------------------------------------
By: STATOIL ENERGY, INC.
SELLER /s/ Stevens V. Gillespie
-------------------------------------------------------------------------------------
Title: Senior Vice President Date: 11/13/98
===================================================================================================================
</TABLE>
PLEASE EXECUTE AND RETURN BY FAX ASAP TO (281) 873-1547.
This confirmation letter will be deemed accepted if no response
is received within two (2) days.
<PAGE> 11
<TABLE>
<CAPTION>
CNG PRODUCING COMPANY
CONFIRMATION LETTER
===================================================================================================================
SELLER: STATOIL ENERGY, INC. BUYER: CNG PRODUCING COMPANY
2800 EISENHOWER AVENUE 16945 NORTHCHASE DRIVE
ALEXANDRIA, VA 22314 SUITE 1750
HOUSTON, TX 77060-2133
ATTN: STEVE GILLESPIE ATTN: TINA HARMON
(703) 317-2237 (281) 873-1568
FAX #: (703) 317-2304 FAX #: (281) 873-1530
===================================================================================================================
<S> <C> <C> <C>
Quantity: Up to 10,000 dth per day
- -------------------------------------------------------------------------------------------------------------------
Type of Service: Firm
- -------------------------------------------------------------------------------------------------------------------
Term: November 1, 1999 through October 31, 2000
- -------------------------------------------------------------------------------------------------------------------
Price: CNG Appalachian Inside FERC First of Month Index plus $0.02
- -------------------------------------------------------------------------------------------------------------------
Delivery Point: Cornwell Transmission Pool
- -------------------------------------------------------------------------------------------------------------------
Pipeline: CNGT
- -------------------------------------------------------------------------------------------------------------------
Special Provisions:
- -------------------------------------------------------------------------------------------------------------------
This purchase is subject to the existing contract between Buyer and Seller.
===================================================================================================================
BUYER By: CNG PRODUCING COMPANY
/s/ Dennis Millet
-------------------------------------------------------------------------------------
Title: Director, Gas Contracts Date:
- -------------------------------------------------------------------------------------------------------------------
By: STATOIL ENERGY, INC.
SELLER /s/ Stevens V. Gillespie
-------------------------------------------------------------------------------------
Title: Senior Vice President Date: 8/31/99
===================================================================================================================
</TABLE>
PLEASE EXECUTE AND RETURN BY FAX ASAP TO (281) 873-1530.
This confirmation letter will be deemed accepted if no response is received
within two (2) days.
<PAGE> 12
<TABLE>
<CAPTION>
CNG PRODUCING COMPANY
CONFIRMATION LETTER
===================================================================================================================
<S> <C> <C> <C>
SELLER: STATOIL ENERGY, INC. BUYER: CNG PRODUCING COMPANY
2800 EISENHOWER AVENUE 16945 NORTHCHASE DRIVE
ALEXANDRIA, VA 22314 SUITE 1750
HOUSTON, TX 77060-2133
ATTN: STEVE GILLESPIE ATTN: TINA HARMON
(703) 317-2237 (281) 873-1568
FAX #: (703) 317-2304 FAX #: (281) 873-1530
===================================================================================================================
Quantity: Up to 4,500 dth per day
- -------------------------------------------------------------------------------------------------------------------
Type of Service: Firm
- -------------------------------------------------------------------------------------------------------------------
Term: August 1, 1999 through July 31, 2000
- -------------------------------------------------------------------------------------------------------------------
Price: CNG Appalachian Inside FERC First of Month Index plus $0.02
- -------------------------------------------------------------------------------------------------------------------
Delivery Point: Cornwell Transmission Pool
- -------------------------------------------------------------------------------------------------------------------
Pipeline: CNGT
- -------------------------------------------------------------------------------------------------------------------
Special Provisions:
- -------------------------------------------------------------------------------------------------------------------
This purchase is subject to the existing contract between Buyer and Seller.
===================================================================================================================
BUYER By: CNG PRODUCING COMPANY
/s/ Dennis Millet
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Title: Director, Gas Contracts Date:
- -------------------------------------------------------------------------------------------------------------------
By: STATOIL ENERGY, INC.
SELLER /s/ Stevens V. Gillespie
-------------------------------------------------------------------------------------
Title: Senior Vice President Date: 8/31/99
===================================================================================================================
</TABLE>
PLEASE EXECUTE AND RETURN BY FAX ASAP TO (281) 873-1530.
This confirmation letter will be deemed accepted if no response is
received within two (2) days.
<PAGE> 1
EXHIBIT 10.8
NATURAL GAS SALES AGREEMENT
This Natural Gas Sales Agreement ("Agreement") is made and entered into
as of the 23rd day of October, 1996, by and between EASTERN ENERGY MARKETING,
INC., a Virginia corporation located at 2900 Eisenhower Avenue, Suite 300,
Alexandria, VA 22314 ("EEM" or "Buyer"), and EASTERN STATES OIL & GAS, INC., a
Virginia corporation located at 2900 Eisenhower Avenue, Suite 300, Alexandria VA
22314, ("ESOG" or "Seller") (hereinafter sometimes referred to singularly as
"Party" and jointly as "Parties").
WITNESSETH:
WHEREAS, ESOG owns and operates certain oil and gas interests,
including oil and gas leases and oil and gas wells, all of which properties are
located in the states of Ohio, West Virginia and Commonwealth of Kentucky (the
"Properties");
WHEREAS, EEM contracts for the purchase of natural gas supply for
resale to its industrial and institutional end-use markets;
WHEREAS, ESOG desires to sell to EEM certain natural gas it produces
and controls originating from the Properties;
WHEREAS, EEM wishes to purchase the natural gas produced by ESOG from
the Properties at the Delivery Points specified herein;
NOW, THEREFORE, in consideration of the premises and covenants
contained herein, the Parties agree as follows:
ARTICLE I
TERM
1.1 The term of this Agreement shall be for an additional two (2) year
period commencing as of November 1, 1995, and ending October 31, 1997 (the
"Initial Term"), and after the Initial Term shall continue month-to-month
thereafter; provided, however, that after the Initial Term, either Party may
renegotiate the provisions of, or terminate entirely, this Agreement by
providing the other Party with thirty (30) days' prior written notice.
1.2 The terms and conditions of this Agreement are intended to
facilitate the entering into by the Parties of a variety of transactions with
specific terms and durations. The terms of this Agreement shall, unless and to
the extent specifically agreed otherwise, apply to and be incorporated in the
Confirmation Letter executed between the Parties using the form attached hereto
at Exhibit A. The type of transactions covered by this Agreement will be
designated on the Confirmation Letter. In case of conflict between the terms of
any Confirmation Letter and the terms of this Agreement the terms of a
Confirmation Letter shall control.
<PAGE> 2
ARTICLE II
CONTRACT QUANTITIES; DELIVERY POINTS
2.1 Seller agrees to sell and deliver, and Buyer agrees to purchase and
receive, the Contract Quantity for a particular transaction in accordance with
the terms of this Agreement and the applicable Confirmation Letter.
2.2 The Delivery Points and point-specific Contract Quantities of the
natural gas produced from the Properties and sold pursuant to this Agreement
shall be identified on the applicable Confirmation Letter.
ARTICLE III
DELIVERY AND PRESSURE
3.1 Seller and Buyer agree to deliver and receive Gas at an
approximately constant rate of flow throughout the term of this Agreement. To
that end, Buyer and Seller shall communicate timely the anticipated market
requirements and supply forecasts for the forthcoming month. Changes in the
availability of supply or ability to take gas shall be communicated between the
Parties immediately and, in order to allow for the effectuation of changes in
Contract Quantities scheduled for transportation, at least twenty-four (24)
hours in advance of their effective date. Imbalance penalties and any related
charges resulting from failure to communicate timely such changes or to take or
dispatch agreed-up confirmed quantities shall be the responsibility of the Party
whose failure caused the imbalance. Notwithstanding the liability established in
the preceding sentence (and without attempting to alter the fixing of that
liability), to the extent changes are not communicated twenty-four (24) hours
prior to their effective date, the Parties shall nonetheless communicate changes
immediately in order to attempt to mitigate scheduling penalties and related
charges, wherever possible pursuant to effective pipeline operating procedures.
Notice of changes provided for in this Section 3.1 shall not relieve the
notifying Party of its delivery obligations provided for in this Agreement.
3.2 The natural gas volumes delivered hereunder shall be at commercial
operating pressures sufficient to deliver such volumes at regulated pressures at
the Delivery Points.
ARTICLE IV
PURCHASE PRICE
4.1 During the term of this Agreement, Buyer shall pay to Seller the
Purchase Price specified on the applicable Confirmation Letter for all Contract
Quantities delivered to the applicable Delivery Point. The Purchase Price shall
include current gathering or pipeline transportation, pipeline shrinkage and
fuel factors and all related surcharges, to deliver Gas to the Point of Sale.
2
<PAGE> 3
ARTICLE V
TAXES
5.1 Seller shall be responsible for and pay for any taxes and charges
attributable to the gas before the Delivery Point. Buyer shall be responsible
for and pay for any taxes and charges attributable to the gas after the Delivery
Point.
ARTICLE VI
PAYMENTS
6.1 Buyer agrees to pay Seller the amount due on or before the later of
forty-five (45) days after the conclusion of the applicable delivery month or
within ten (10) days after Buyer's receipt of the Transporters' statements
showing actual metered Contract Quantities received at the applicable
Transporters' receipt point (the "Due Date"). Any Due Date falling on a holiday
or weekend will be scheduled for payment the next working day.
6.2 Buyer's payments shall reflect the total Contract Quantities
delivered to Buyer during the applicable month, the Purchase price and the total
dollar amount due.
6.3 If Buyer or Seller, in good faith, disputes the amount of any such
payment or any part thereof, Buyer will pay to Seller such amount acknowledged
to be correct. If it is ultimately determined that Buyer owes the disputed
amount, Buyer will pay Seller that amount upon such determination, plus any
costs and expenses necessarily incurred to obtain such ultimate determination,
including reasonable attorneys fees and related costs.
6.4 The parties shall have the right, upon reasonable notice and at
reasonable times, to examine the books and records of the other to the extent
reasonably necessary to verify the accuracy of any statement, payment demand,
charge, payment or computation made under the Agreement. Provided, however, that
any such audit and any claim based upon errors in any statement must be made
within two (2) years of the date of such statement.
ARTICLE VII
GAS QUALITY AND MEASUREMENT
7.1 Seller shall sell and deliver to Buyer at the Delivery Points gas
that is merchantable and meets all the specifications, quality and pressure
which are required by the Transporters. Measurement, testing and heat content of
the gas purchased hereunder shall be measured on a dry basis, and shall be
governed by the Transporters' applicable measurement procedures.
7.2 Contract Quantities shall ultimately be determined by a
reconciliation of Seller's monthly gas supply reports and the Transporters'
monthly transportation statements. Buyer and Seller shall cooperate to determine
the Contract Quantities flowing into the Transporters. In the
3
<PAGE> 4
event that Seller and Buyer do not agree on the monthly Contract Quantities,
Buyer and Seller agree to work together to reconcile any volume discrepancies.
ARTICLE VIII
WARRANTY
8.1 Seller warrants that it will at the time of delivery have good and
marketable title to, and the right to sell all gas to be sold and delivered
hereunder and that the gas is free and clear from all liens and adverse claims
of every kind, and agrees to indemnify and save harmless and defend Buyer from
all suits, actions, accounts, damages, costs, losses and expenses (including
reasonable attorney's fees) arising from or connected with the adverse claim of
any person to title to said gas.
ARTICLE IX
TITLE AND LIABILITY
9.1 Seller shall indemnify, defend and hold Buyer harmless from and
against any liability or loss whatsoever (including costs and reasonable
attorney's fees in connection therewith) due to personal injury or death or
damage to or destruction of property arising out of or occurring during Seller's
possession of any gas to be delivered hereunder except as otherwise provided in
this Agreement.
9.2 Buyer shall indemnify and hold Seller harmless from and against any
liability or loss whatsoever (including costs and attorney's fees in connection
therewith) due to personal injury or death or damage to or destruction of
property arising out of or occurring during Buyer's possession of any gas to be
delivered hereunder except as otherwise provided in this Agreement.
9.3 Title to gas sold hereunder and possession thereof shall pass from
the Seller to Buyer at the Delivery Points.
9.4 Neither party shall be responsible for consequential or punitive
damages.
ARTICLE X
FORCE MAJEURE
10.1 If Seller or Buyer is rendered unable, wholly or in part, by force
majeure to carry out its obligations under this Agreement, Seller or Buyer shall
give to all other parties prompt written notice of the force majeure with
reasonable full particulars thereof; thereupon, the obligations of Seller or
Buyers so far as they are affected by the force majeure, shall be suspended
during the continuance of the force majeure. Seller or Buyer shall use all
reasonable diligence to remove the force majeure as quickly as possible.
10.2 The requirement that any force majeure shall be remedied with all
reasonable diligence shall not require the settlement of strikes, lockouts, or
other labor difficulty contrary to the
4
<PAGE> 5
wishes of the party suffering the difficulty; the manner in which such labor
difficulties shall be handled shall be entirely within the discretion of the
party suffering the difficulty.
10.3 The term "force majeure" as here employed shall mean an act of
God, strike, lockout, or other industrial disturbances, act of the public enemy,
war blockade, public disturbance, lightning, fire, storm, flood, freeze,
explosion, governmental restraint, compressor failure, pipeline ruptures, and
any other cause, whether the kind specifically enumerated above or otherwise,
which is not reasonably within the control of the parties. The term "force
majeure" specifically excludes increases or decreases in gas supply due to
allocation or reallocation of production by Seller, pipelines or other parties,
economic hardship or movements in the price of natural gas or other fuels that
would make the performance of the Agreement burdensome or undesirable for either
party.
ARTICLE XI
NOTICES
11.1 All notices and written communications between the parties hereto
including Seller's invoices and Buyer's remittances, shall become effective when
delivered by the parties in accordance with the provisions of this Agreement to
the following addresses:
BUYER
Notices to: EASTERN ENERGY MARKETING, INC.
Attention: John A. Schultz
2900 Eisenhower Avenue, Suite 300
Alexandria, VA 22314
Telephone: (703) 317-2300
Facsimile: (703) 317-2201
SELLER
Notices to: EASTERN STATES OIL & GAS, INC.
2900 Eisenhower, Suite 300
Alexandria, VA 22314
Attention: Stevens V. Gillespie
Telephone: (703) 317-2327
Facsimile: (703) 317-2301
5
<PAGE> 6
Payments to: EASTERN STATES OIL & GAS, INC.
2900 Eisenhower, Suite 300
Alexandria, VA 22314
Attention: Stevens V. Gillespie
Telephone: (703) 317-2327
Facsimile: (703) 317-2301
11.2 Either Party may change the information, including changes, of
personnel, set out in paragraph (a) immediately above by providing the other
party with prior notice. Notice may be oral but such oral notice shall be
followed with written notice within five (5) business days.
11.3 Notices required by this Agreement may be made by
telecommunications transmission (e.g., facsimile or telecopy), including
presentation of invoices, and such telecommunication shall constitute acceptable
presentation of notice and invoices under this Agreement. If notices are sent by
overnight mail, an employee signature shall constitute receipt.
ARTICLE XII
LAWS AND REGULATIONS
12.1 This Agreement shall be subject to all applicable and valid laws,
ordinances, rules and regulations of federal, state or local authorities having
jurisdiction now or hereafter having jurisdiction over the Parties; and should
either of the Parties, by force of any such law or regulation imposed at any
time during the term of this Agreement, be rendered unable, wholly or in part,
to carry out its obligations under this Agreement, other than an obligation to
make payments due hereunder, then this Agreement shall continue nevertheless and
shall then be deemed modified to confirm with the requirements of such law or
regulation. Notwithstanding the above, this Agreement shall not be deemed to be
so modified if such law or regulation substantially and materially prohibits the
Parties from performing hereunder or has the affect of materially altering the
economic position of the Parties or either of them; then the party hereby
injured may, by written notice to the other Party, require that this Agreement
or other arrangements incidental to this Agreement be amended as necessary to
preserve the economic position held by the affected Party immediately prior to
such event. Such notice shall describe the action taken by the regulatory
authority and shall include reasonable particulars as to the manner and extent
to which the economic position of the Party giving the notice has been adversely
affected. The Parties shall use all their reasonable efforts during a sixty (60)
Day period following such notice to negotiate and effect such amendments.
6
<PAGE> 7
ARTICLE XIII
MISCELLANEOUS
13.1 This Agreement constitutes the entire Agreement between the
Parties hereto. There are no prior or contemporaneous Agreements or
representations affecting such subject matter other than those expressed in the
Agreement.
13.2 No modification or change herein shall be enforceable, except as
specifically provided for in the Agreement, unless reduced to writing and
executed by both Parties.
13.3 No assignment of this Agreement or any of the rights or
obligations hereunder shall be made by either Party unless the other Party has
consented in writing thereto, which consent shall not be unreasonably withheld
or delayed; provided, however, either Party may assign or pledge this Agreement
under the provisions or any mortgage, deed of trust, indenture, by operation of
law or similar instrument which it has executed or may execute.
13.4 The Agreement shall be governed by and construed, enforced and
performed in the State of Virginia, without regard to principles of conflicts of
law. The Parties acknowledge and agree that the provisions of the Uniform
Commercial Code will apply to all aspects of transactions and confirmations
engaged in and entered into under this Agreement.
13.5 In no event shall either Party be liable for any punitive,
incidental, consequential, direct, indirect, or other damages not expressly set
forth herein.
13.6 The headings used for the Articles herein are for convenience and
reference purposes only and shall in no way affect the meaning or interpretation
of the provisions of the Agreement.
13.7 The terms of this Agreement including but not limited to the
Purchase Price, the Contract Quantities, the identified Transporter(s), and all
other material terms thereof shall be kept confidential by the Parties hereto,
except that any information must be disclosed to a third-party for the purpose
of effectuating transportation of Gas subject to this Agreement or to meet New
York Mercantile Exchange requirements or regulatory filing requirements where
necessary, or as otherwise required by law.
7
<PAGE> 8
IN WITNESS WHEREOF, this Agreement shall be binding upon the parties
hereto and upon their respective heirs, successors, representatives and assigns.
The Seller and Buyer have caused this Agreement to be executed by their duly
authorized officers as of the date first above written.
BUYER:
EASTERN ENERGY MARKETING, INC.
By: /s/ John A. Herbert
---------------------------------------
John A. Herbert
Senior Vice President
SELLER:
EASTERN STATES OIL & GAS, INC.
By: /s/ Stevens V. Gillespie
---------------------------------------
Stevens V. Gillespie
Senior Vice President
8
<PAGE> 9
CONFIRMATION LETTER
Date: November 1, 1998 STATOIL ENERGY, Inc.
PLEASE DELIVER IMMEDIATELY UPON RECEIPT TO: HUGH BYERS
PHONE NO.: (304) 343-9566
FAX NO: (304) 344-0363
This letter serves to confirm the following agreement entered into by and
between STATOIL ENERGY SERVICES, INC. and BLAZER ENERGY CORPORATION and subject
to the General Terms and Conditions agreed to and entered into by the parties
hereto.
BUYER: STATOIL ENERGY SERVICES, INC.
SELLER: BLAZER ENERGY CORPORATION
TYPE OF TRANSACTION: Baseload - Term
TERM: November 1, 1998 through October 31, 1999
CONTRACT QUANTITIES (Dth): 66,000 Dth per day
PURCHASE PRICE (Dth): The Purchase Price per Dth for the Contract
Quantities set forth above will be calculated
monthly based on the Inside F.E.R.C. Columbia Gas
Appalachia Index plus $0.02 per Dth.
POINT OF SALE: Columbia Gas Transmission (WV & KY)
POINT OF DELIVERY: Columbia Gas Transmission (WV & KY)
SPECIAL PROVISIONS: The parties have respective firm obligations to
deliver and to receive the Contract Quantities.
Force Majeure due to disruption of pipeline service
is limited to interruption or curtailment of firm
transportation by the transporting pipeline(s).
THE PROVISIONS WITHIN THIS CONFIRMATION LETTER SHALL BE CONCLUSIVELY DEEMED
ACCURATE AND COMPLETE TO THE EXTENT IT IS NOT OBJECTED TO, IN WRITING, WITHIN
TWENTY-FOUR (24) HOURS OF RECEIPT.
STATOIL ENERGY SERVICES, INC. BLAZER ENERGY CORPORATION
By: /s/ Mark A. Williams By: /s/ Stevens V. Gillespie
------------------------------- -----------------------------------
Name: Mark A. Williams Name: Stevens V. Gillespie
Title: Manager, Appalachian Supply Title: Senior Vice President
<PAGE> 10
CONFIRMATION LETTER
Date: January 4, 1999 STATOIL ENERGY, INC.
ESOG Contract # WV-S-0188
PLEASE DELIVER IMMEDIATELY UPON RECEIPT TO: HUGH BYERS
PHONE NO.: (304) 343-9566
FAX NO: (304) 343-0363
This letter serves to confirm the following agreement entered into by and
between STATOIL ENERGY SERVICES, INC. and EASTERN STATES OIL & GAS, INC. and
subject to the General Terms and Conditions agreed to and entered into by the
parties hereto.
BUYER: STATOIL ENERGY SERVICES, INC.
SELLER: BLAZER ENERGY CORP.
TYPE OF TRANSACTION: Baseload - Term
TERM: November 1, 1998 through October 31, 2001
CONTRACT QUANTITIES (DTH): 4,134 Dth per day
PURCHASE PRICE (DTH): 100 percent (100%) of that price published
in the first monthly issue of Inside
F.E.R.C.'s Gas Market Report, Index Price
per Dth, CNG Gas Transmission Corporation
("CNG"), Appalachia Index plus $0.02 per
Dth.
POINT OF SALE: Equitrans Meter Nos. 22379, 23509, 23510,
23511, 23512, 23513
POINT OF DELIVERY: Equitrans City Gate
SPECIAL PROVISIONS: The parties have respective firm obligations
to deliver and to receive the Contract
Quantities. Force Majeure due to disruption
of pipeline service is limited to
interruption or curtailment of firm
transportation by the transporting
pipeline(s).
THE PROVISIONS WITHIN THIS CONFIRMATION LETTER SHALL BE CONCLUSIVELY DEEMED
ACCURATE AND COMPLETE TO THE EXTENT IT IS NOT OBJECTED TO, IN WRITING, WITHIN
TWENTY-FOUR (24) HOURS OF RECEIPT.
STATOIL ENERGY SERVICES, INC. BLAZER ENERGY CORP.
By: /s/ Mark A. Williams By: /s/ Stevens V. Gillespie
-------------------------------------- ---------------------------------
Name: Mark A. Williams Name: Stevens V. Gillespie
Title: Manager, Appalachian Supply Title: Senior Vice President
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference to our firm under the caption
"Experts" and to the use of our report dated August 23, 1999 (except Note 12,
as to which the date is October 13, 1999) with respect to the consolidated
financial statements of Eastern Oil & Gas, Inc.; our report dated August 23,
1999 with respect to the consolidated income statement and cash flows of the
domestic operations of Blazer Energy Corp. and subsidiary (formerly Ashland
Exploration, Inc.); our report dated August 23, 1999 (except Note 2, as to
which the date is October 13, 1999) with respect to the statement of assets
and trust corpus of the Appalachian Natural Gas Trust (formerly Appalachian
Basin Royalty Trust); and our report dated October 6, 1999 (except Note 5, as
to which the date is October 13, 1999) with respect to the statements of
revenues and direct operating expenses of the Underlying Properties of Eastern
States Oil & Gas, Inc. included in Amendment No. 1 to the Registration
Statement (Form S-1) and related Prospectus of the Appalachian Natural Gas
Trust and Eastern States Oil & Gas, Inc. for the registration of beneficial
interest in the Appalachian Natural Gas Trust.
/s/ ERNST & YOUNG LLP
Vienna, Virginia
October 13, 1999
<PAGE> 1
[RYDER SCOTT LETTERHEAD]
EXHIBIT 23.4
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the use of our Firm's name in Amendment No. 1 to the
Registration Statement on Form S-1/S-1 for the Appalachian Natural Gas Trust and
Eastern States Oil & Gas, Inc. to which this consent is an exhibit. We further
consent to the reference to our Firm under the heading "Experts" in the
Registration Statement.
/s/ RYDER SCOTT COMPANY, L.P.
Houston, Texas
October 13, 1999
