<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JULY 15, 1999
REGISTRATION NO. 333-
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933
ON
<TABLE>
<S> <C>
FORM S-1 FORM S-3
OCEAN ENERGY ROYALTY TRUST OCEAN ENERGY, INC.
(Exact name of co-registrant as specified in its (Exact name of co-registrant as specified in its
charter) charter)
DELAWARE TEXAS
(State or other jurisdiction (State or other jurisdiction
of incorporation or organization) of incorporation of organization)
1311 1311
(Primary Standard Industrial (Primary Standard Industrial
Classification Code Number) Classification Code Number)
[APPLIED FOR] 74-1764876
(I.R.S. Employer Identification No.) (I.R.S. Employer Identification No.)
910 TRAVIS, 5TH FLOOR 1001 FANNIN, SUITE 1600
HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002
(302) 777-6560 (713) 265-6000
(Address, including zip code, and telephone number, (Address, including zip code, and telephone number,
including area code, of Registrant's principal including area code, of Registrant's principal
executive offices) executive offices)
SUSAN BREM ROBERT K. REEVES
910 TRAVIS, 5TH FLOOR EXECUTIVE VICE PRESIDENT,
HOUSTON, TEXAS 77002 GENERAL COUNSEL AND SECRETARY
(713) 751-6834 1001 FANNIN, SUITE 1600
HOUSTON, TEXAS 77002
(Name, address, including zip code, and telephone (713) 265-6000
number, including area code, of agent for service) (Name, address, including zip code, and telephone
number, including area code, of agent for service)
</TABLE>
---------------------
Copies to:
<TABLE>
<S> <C>
J. MARK METTS ROBERT V. JEWELL
VINSON & ELKINS L.L.P. ANDREWS & KURTH L.L.P.
1001 FANNIN, 2300 FIRST CITY TOWER 600 TRAVIS, SUITE 4200
HOUSTON, TEXAS 77002-6760 HOUSTON, TEXAS 77002
(713) 758-2222 (713) 220-4300
</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, 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, 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. [ ]
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
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PROPOSED
TITLE OF EACH CLASS OF MAXIMUM AGGREGATE AMOUNT OF
SECURITIES TO BE REGISTERED OFFERING PRICE(1) REGISTRATION FEE
- - ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Units of Beneficial Interest in Ocean Energy Royalty
Trust..................................................... $100,000,000 $27,800
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</TABLE>
(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(o).
THE REGISTRANTS HEREBY AMEND THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANTS
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 SECURITIES AND EXCHANGE 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. THE TRUST MAY NOT SELL THESE SECURITIES 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 THE TRUST IS
NOT SOLICITING TO BUY THESE SECURITIES IN ANY JURISDICTION WHERE THE OFFER OR
SALE IS NOT PERMITTED.
SUBJECT TO COMPLETION. DATED JULY 15, 1999.
OCEAN ENERGY ROYALTY TRUST
9,000,000 Trust Units
----------------------
This is an initial public offering of units of beneficial interest in the
Ocean Energy Royalty Trust. The trust is offering all of the trust units to be
sold in this offering. At completion of the offering, the trust will acquire net
profits interests in natural gas producing properties from Ocean Energy, Inc. in
exchange for the payment by the trust to Ocean of all of the net proceeds of
this offering and the issuance by the trust to Ocean of 3,000,000 trust units.
Prior to this offering there has been no public market for the trust units.
The trust expects the initial public offering price of the trust units to be
between $ and $ per unit. The trust intends to apply to have the
trust units approved for listing on the New York Stock Exchange under the symbol
" ".
THE TRUST UNITS. Trust units are units of beneficial interest in the trust
and represent undivided interests in the trust. They do not represent any
interest in Ocean.
THE TRUST. The trust will own net profits interests in natural gas
producing properties located in the Arkoma Basin in Arkansas and Oklahoma
and in the Bear Paw area of Montana. The net profits interests will entitle
the trust to receive 45% of the net proceeds from the sale of production
from these properties owned by Ocean.
THE TRUST UNITHOLDERS. As a trust unitholder, you will receive monthly
distributions of cash that the trust receives for its net profits interests
from the sale of natural gas or oil produced from the underlying
properties.
See "Risk Factors" beginning on page 9 to read about certain information
you should consider before purchasing trust units.
----------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY
BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY
OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.
----------------------
<TABLE>
<CAPTION>
Per
Trust Unit Total
---------- --------
<S> <C> <C> <C> <C>
Initial public offering price............................... $ $
Underwriting discount....................................... $ $
Proceeds, before expenses, to the trust..................... $ $
</TABLE>
The underwriters may, under certain circumstances, purchase from Ocean up
to an additional 1,350,000 trust units at the initial public offering price less
the underwriting discount.
----------------------
The underwriters expect to deliver the trust units against payment in New
York, New York on , 1999.
GOLDMAN, SACHS & CO. MERRILL LYNCH & CO.
----------------------
Prospectus dated , 1999.
<PAGE> 3
[MAP]
[Map illustrating locations of underlying properties in Arkoma Basin and Bear
Paw area.]
<PAGE> 4
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 Certain Oil and Natural Gas Terms." Miller
and Lents, Ltd., an independent engineering firm, provided the estimates of
proved oil and natural gas reserves as of July 1, 1999 included in this
prospectus. These estimates are contained in summaries prepared by Miller and
Lents of the reserve reports as of July 1, 1999 for the underlying properties
described below and for the net profits interests in the underlying properties
that will be held by the trust following the offering. The Miller and Lents
summaries are located at the back of this prospectus as Exhibits A and B and are
referred to in the prospectus as the reserve report. References to "Ocean" in
this prospectus include Ocean Energy, Inc. and its subsidiaries. Unless
otherwise indicated, all information in this prospectus assumes no exercise of
the underwriters' over-allotment option.
OCEAN ENERGY ROYALTY TRUST
Ocean Energy Royalty Trust was formed by Ocean in July 1999. Upon
completion of this offering, Ocean will convey to the trust net profits
interests in oil and natural gas producing properties that it owns in the Arkoma
Basin in Arkansas and Oklahoma and in the Bear Paw area in Montana. Although the
trust will benefit from any oil or liquids produced from the underlying
properties, substantially all of the production from these properties is natural
gas. We refer to Ocean's interests in these properties as the underlying
properties.
The net profits interests will entitle the trust to receive 45% of the net
proceeds from the sale of production from the underlying properties. Each month
Ocean will collect cash received from the sale of production and deduct property
and production taxes, development, production, transportation and marketing
costs and overhead.
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 at any time costs should exceed gross proceeds, neither the
trust nor the trust unitholders would be liable for the excess costs. However,
the trust would not receive any net proceeds until future net proceeds exceed
the total of those excess costs, plus interest at the prime rate.
Ocean will calculate the net proceeds from the underlying properties
separately for each of the states where the underlying properties are located.
Any excess costs for the underlying properties in one state will not reduce net
proceeds calculated for the underlying properties in another state.
Ocean does not expect future production costs for the underlying properties
to change significantly as compared to recent historical expenditures.
Similarly, Ocean expects development costs for the underlying properties to be
consistent with recent historical expenditures.
The trust will make monthly distributions of substantially all of its
income to trust unitholders. The first monthly distribution is expected to be
made in 1999. On your federal income tax return, you will be required
to include your allocable share of trust net income. In addition, you will be
entitled to claim a depletion deduction relating to production from the
underlying properties. The deductions will permit you to defer or reduce taxes
on a portion of the income you receive from the trust.
1
<PAGE> 5
OCEAN'S OWNERSHIP INTERESTS IN THE TRUST AND THE UNDERLYING PROPERTIES
Ocean's interests in the underlying properties are predominantly "working
interests," which require Ocean to bear the costs of exploration, production and
development on the underlying properties.
Ocean's initial retained interest in the underlying properties will entitle
it to 55% of the net proceeds from production. Ocean will also own 25% of the
outstanding trust units immediately after the offering, assuming no exercise of
the underwriters' over-allotment option. Under the trust agreement governing the
trust, Ocean will have the right at any time to reduce its retained interest in
the underlying properties by conveying additional net profits interests in the
underlying properties to the trust in exchange for additional trust units. Any
additional trust units will be issued at the fixed rate of 266,666 units for
each additional 1% of net profits interest conveyed, which is the same ratio as
the initial trust units bear to the initial net profits interests conveyed to
the trust. The total additional net profits interests in the underlying
properties conveyed to the trust will not exceed 35%. Ocean believes that a
retained ownership interest in 20% or more of the net proceeds from production
on the underlying properties will provide adequate incentive to operate and
develop the underlying properties in an efficient and cost effective manner.
Ocean is under no obligation to continue to own the underlying properties, but
currently intends to do so.
The following chart shows the manner in which the net profits from the
underlying properties will be divided among Ocean, the trust and the public
trust unitholders immediately after the offering, assuming no exercise of the
underwriters' over-allotment option.
[CHART ILLUSTRATING DISTRIBUTION OF NET PROCEEDS & OWNERSHIP OF TRUST UNITS]
2
<PAGE> 6
THE UNDERLYING PROPERTIES
The underlying properties are located in the Arkoma Basin in Arkansas and
Oklahoma and the Bear Paw area in Montana. The Arkoma Basin is one of the more
significant natural gas producing areas in the United States. The Bear Paw area
is a shallow natural gas field operated primarily by Ocean. Approximately 53% of
the proved reserves on the underlying properties are located in the Arkansas
portion of the Arkoma Basin, 7% are located in the Oklahoma portion of the
Arkoma Basin, and 40% are located in the Bear Paw area of Montana. Wells in
these areas have been producing for many years and are characterized by moderate
rates of annual decline in production and low production costs.
PRODUCING AREAS
As of July 1, 1999, proved reserves of the underlying properties, which are
nearly all natural gas producing leases, were estimated at 339 Bcf of natural
gas. The productive areas include:
- Arkoma Basin. The underlying properties in the Arkoma Basin consist of
long-lived natural gas reserves in northwestern Arkansas and eastern
Oklahoma. The Arkoma Basin has produced over 13 Tcf of natural gas since
the early 1900s. Production occurs from sands ranging in depth from less
than 1,000 feet to more than 10,000 feet, with various known producing
zones. Projected average daily net production in the underlying
properties in this area during calendar year 2000, as derived from the
reserve report, is approximately 53.7 MMcf of natural gas.
- Bear Paw Area. The underlying properties in this area are located in
north central Montana. Since its discovery in 1966, the area has produced
in excess of 500 Bcf of natural gas. Wells in the area produce from
formations at 1,200 to 2,000 feet. Projected average daily net production
in the underlying properties in this area during calendar year 2000, as
derived from the reserve report, is approximately 39.1 MMcf of natural
gas.
LOW RISK RESERVES
Proved developed reserves are the most valuable and lowest risk category of
reserves because their production requires no significant future development
costs. Proved developed reserves account for 90% of the discounted present value
of estimated future net revenues represented by the underlying properties. In
addition, 80% of the proved reserves associated with the underlying properties
are producing reserves.
CONTROL OF OPERATIONS
The right to operate an oil and natural gas lease is important because the
operator controls the timing and amount of discretionary expenditures for
operational and development activities. Ocean operates approximately 88% of the
underlying properties, based on 1998 production. Ocean operates 863 gross wells
and owns additional interests in 341 wells on the underlying properties.
HISTORY OF LOW COST RESERVE ADDITIONS
Ocean has a record of successfully adding reserves to the underlying
properties through development at costs substantially below the industry
average. Over the last three years Ocean added approximately 66 Bcfe of proved
reserves to the underlying properties through drilling at an average cost of
$0.54 per Mcfe. In addition, over the same period Ocean had upward revisions of
reserve estimates on the underlying properties of approximately 43 Bcfe. These
additions and upward revisions replaced 112% of production at a total finding
and development cost of $0.33 per Mcfe.
3
<PAGE> 7
EFFECT OF PLANNED DEVELOPMENT PROGRAM
The underlying properties represent Ocean's undivided interests in oil and
natural gas leases and the production from existing and future wells on those
leases. Accordingly, if Ocean successfully drills additional wells on acreage
covered by these leases or successfully conducts other development activities,
those activities will enhance production from the underlying properties and the
trust will benefit from increased production.
Without development projects, the underlying properties would typically
experience a 13% annual natural rate of decline in production. The planned
development expenditures included in the reserve report are expected to reduce
the rate of decline in production to approximately 4% per year. Ocean intends to
spend additional amounts to further develop the underlying properties, which
Ocean believes should reduce the rate of decline in production to approximately
2% per year for at least the next three years.
ADDITIONAL DEVELOPMENT OPPORTUNITIES
Ocean believes that the underlying properties will offer economic
development projects that are not included in existing proved reserves. These
additional development opportunities could significantly increase production and
proved reserves and offset the normal rate of decline.
Costs per Mcfe associated with reserves added through additional
development projects are expected to be consistent with historical costs. Costs
will be deducted from the net profits interests as they are paid and will lower
monthly distributions. These projects should slow the decline in production,
resulting in additional net proceeds available for distribution by the trust in
subsequent years.
Additional development opportunities include:
- adding compression;
- performing mechanical and chemical treatments to stimulate production
rates; and
- drilling additional wells, some of which may utilize horizontal well
technology.
Ocean believes each type of additional development opportunity will be
implemented in each of the productive areas over a period of years. Although
actual development costs incurred will depend on the results of these
development activities, Ocean expects total annual development costs for both
planned development and additional development opportunities will be
approximately $10 to 11 million on the underlying properties for at least the
next five years.
Ocean 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. Ocean
allocates discretionary resources for development based on expected rates of
return. The underlying properties have historically provided attractive rates of
return on development projects compared to Ocean's other properties, and are
expected to continue to do so in the future.
4
<PAGE> 8
SUBSTANTIAL OPERATING MARGINS
The underlying properties have historically generated substantial operating
margins. The following table shows Ocean's operating information per Mcfe for
the underlying properties for each of the years ended December 31, 1996, 1997
and 1998 and the twelve months ended March 31, 1999.
<TABLE>
<CAPTION>
TWELVE
MONTHS
YEAR ENDED DECEMBER 31, ENDED
------------------------ MARCH 31,
1996 1997 1998 1999
------ ------ ------ ---------
<S> <C> <C> <C> <C>
Sales price (net of transportation costs)................. $2.10 $1.97 $1.63 $1.55
Expenses:
Production expenses..................................... 0.16 0.15 0.17 0.17
Production and property taxes........................... 0.09 0.10 0.08 0.08
Overhead................................................ 0.07 0.07 0.09 0.09
----- ----- ----- -----
Total expenses.................................. 0.32 0.32 0.34 0.34
----- ----- ----- -----
Operating margin.......................................... $1.78 $1.65 $1.29 $1.21
===== ===== ===== =====
</TABLE>
CONTROL OF NATURAL GAS GATHERING SYSTEMS
In the Bear Paw area, a majority-owned subsidiary of Ocean operates natural
gas gathering systems for nearly all of the production from the underlying
properties. Through its ownership of gathering operations, Ocean is able to
optimize natural gas production. In the Arkoma Basin, Ocean markets its natural
gas production through gathering systems primarily operated by third parties.
PROVED RESERVES
The following table provides, as of July 1, 1999, estimated proved natural
gas reserves and undiscounted and discounted estimated future net cash flows for
the underlying properties and the net profits interests. Proved reserves in the
table are based on an average natural gas price realized by Ocean as of July 1,
1999, which was $1.68 per Mcf of natural gas. The amounts of estimated future
net cash flows from proved reserves shown in the table are before income taxes.
Discounted future net cash flows are based on a discount rate of 10%, which is
the rate required by the Securities and Exchange Commission. Reserve estimates
are subject to revision.
<TABLE>
<CAPTION>
PROVED ESTIMATED FUTURE NET CASH FLOWS
RESERVES FROM PROVED RESERVES
--------- -------------------------------------
GAS(MMCF) UNDISCOUNTED DISCOUNTED
--------- --------------- -------------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
Underlying properties (100%):
Arkoma Basin
Arkansas................................ 178,556 $274,175 $154,027
Oklahoma................................ 23,313 31,181 16,869
Bear Paw Area
Montana................................. 137,301 98,310 54,835
-------- -------- --------
Total.............................. 339,170 $403,666 $225,731
======== ======== ========
Underlying properties (45%).................. 152,627 $181,826 $101,690
Net profits interest (a)..................... 113,037 $181,826 $101,690
Per trust unit............................... 9.42 $ 15.15 $ 8.47
</TABLE>
- - ---------------
(a) Proved reserves for the net profits interests are calculated by determining
the amount of reserves with sufficient value to pay 45% of the future
estimated costs, before overhead and trust administrative expenses, that are
deducted in calculating net profits, and subtracting that amount from 45% of
proved reserves of the underlying properties. Overhead charged to the
underlying properties operated by Ocean was $2.8 million in 1998 and trust
administrative expenses are expected to be approximately $ per
year. Accordingly, 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.
5
<PAGE> 9
HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES
The following table provides natural gas sales volumes, average sales
prices, revenues, direct operating expenses, development costs and overhead
relating to the underlying properties for each of the years ended December 31,
1996, 1997 and 1998 and for the three months ended March 31, 1998 and 1999. The
unaudited statements were prepared on a basis consistent with the audited
statements and, in the opinion of Ocean, include all adjustments (consisting
only of normal recurring adjustments) necessary to present fairly the revenues,
direct operating expenses, development costs and overhead relating to the
underlying properties for the periods presented. See the audited statements of
revenues and direct operating expenses of the underlying properties for the
years ended December 31, 1996, 1997 and 1998 and the unaudited statements of
revenues and direct operating expenses of the underlying properties for the
three months ended March 31, 1998 and 1999 beginning on page F-3 in this
prospectus.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
--------------------------- -------------------
1996 1997 1998 1998 1999
------- ------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
Natural Gas Sales Volume (Mcfe).......... 30,736 34,197 33,067 8,428 8,175
Natural Gas Average Price (per Mcfe)..... $ 2.10 $ 1.97 $ 1.63 $ 1.78 $ 1.46
Gas Sales Revenues (net of transportation
costs)................................. $64,557 $67,457 $54,048 $15,042 $11,929
Direct Operating Expenses:
Production and property taxes.......... 2,721 3,333 2,793 691 526
Production expenses.................... 5,017 5,239 5,785 1,579 1,412
------- ------- ------- ------- -------
Total.......................... 7,738 8,572 8,578 2,270 1,938
------- ------- ------- ------- -------
Excess of Revenues over Direct Operating
Expenses............................... $56,819 $58,885 $45,470 $12,772 $ 9,991
======= ======= ======= ======= =======
Development Costs........................ $ 8,623 $12,005 $15,183 $ 3,260 $ 691
======= ======= ======= ======= =======
Overhead................................. $ 2,153 $ 2,435 $ 2,831 $ 629 $ 756
======= ======= ======= ======= =======
</TABLE>
6
<PAGE> 10
2000 PROJECTED CASH DISTRIBUTIONS
The following table provides projected cash distributions to be received by
trust unitholders during the year 2000. The calculations assume realized prices
of $1.90 per Mcf of natural gas, which is based on an assumed $2.40 per MMBtu
NYMEX price, and assume sales volumes indicated in the reserve report. The
projections were prepared by Ocean as its best estimate of cash distributions to
trust unitholders during calendar year 2000, based on these pricing assumptions
and other assumptions that are described in "Projected Cash Distributions --
Significant Assumptions Used to Prepare the 2000 Projected Cash Distributions."
Our independent auditors have not examined, compiled or otherwise applied
procedures to the projections presented herein and, accordingly, do not express
an opinion or any other form of assurance on them. Because the trust does not
receive cash with respect to production from the underlying properties until
approximately 60 days after the end of the month in which production occurs, the
projections are derived from an estimate of production from October 1999 through
September 2000. The projections and the assumptions on which they are based are
subject to significant uncertainties, many of which are beyond the control of
Ocean or the trust. ACTUAL CASH DISTRIBUTIONS TO TRUST UNITHOLDERS DURING
CALENDAR YEAR 2000, THEREFORE, COULD VARY SIGNIFICANTLY BASED UPON CHANGES IN
ANY OF THESE ASSUMPTIONS. Cash distributions to trust unitholders will be
particularly sensitive to fluctuations in natural gas prices. See "Projected
Cash Distributions -- Sensitivity of 2000 Projected Cash Distributions to
Natural Gas Prices" which shows estimated effects to cash distributions from
changes in natural gas prices. As a result of typical production declines for
natural gas properties, production estimates generally decrease from year to
year. ACCORDINGLY, THE PROJECTED 2000 CASH DISTRIBUTIONS ARE NOT NECESSARILY
INDICATIVE OF DISTRIBUTIONS FOR FUTURE YEARS. Because payments to the trust will
be generated by depleting assets, a portion of each distribution may represent a
return of your original investment. See "Risk Factors -- Trust Assets Are
Depleting Assets."
<TABLE>
<CAPTION>
AMOUNT
---------------------
(IN THOUSANDS,
EXCEPT PER UNIT DATA)
<S> <C> <C>
Underlying Properties
Natural Gas Sales Volumes (Mcfe)................. 34,162
Natural Gas Assumed Sales Price (per Mcfe)....... $ 1.90
Calculation of Distributable Income
Natural Gas Sales Revenues....................... $64,957
Costs:
Production and property taxes................. 3,313
Production expenses........................... 4,479
Overhead...................................... 3,324
Development costs............................. 11,000
-------
Total.................................... 22,116
-------
Net proceeds..................................... 42,841
Net profits percentage........................... 45%
-------
Trust royalty income............................. 19,278
Trust administrative expense..................... 500
-------
Trust distributable income....................... $18,778
=======
</TABLE>
<TABLE>
<CAPTION>
CASH DISTRIBUTION
AS A PERCENTAGE
OF $ TRUST
UNIT PRICE
-----------------
<S> <C> <C>
Per Trust Unit (12,000,000 Trust Units):
Total cash distributions......................... $
Cost depletion tax deduction.....................
-------
Taxable income...................................
Income tax rate..................................
-------
Income tax expense...............................
-------
Total cash distributions after tax....... $
=======
</TABLE>
7
<PAGE> 11
THE OFFERING
Trust units offered
by the trust............. 9,000,000
Trust units outstanding
after the offering......... 12,000,000, of which 3,000,000 will be owned by
Ocean, assuming no exercise of the underwriters'
over-allotment option.
Future trust units that may
be issued to Ocean upon
contribution of
additional
net profits interests to
the trust................ up to 9,333,310
Use of proceeds............ The trust will contribute all net proceeds from
this offering to Ocean and issue 3,000,000 trust
units to Ocean in exchange for a 45% net profits
interest in the underlying properties from Ocean.
Ocean will use the cash it receives from the trust
to repay indebtedness under its existing revolving
credit facility.
Proposed NYSE symbol.......
Ocean intends to grant its executive officers options to purchase up to
$ million of its trust units at the initial public offering price. The
executive officers will not receive any trust distributions until their options
are exercised.
INVESTING IN TRUST UNITS
Investing in the trust units differs from investing in corporate stock in
the following ways:
- to the extent provided in the trust agreement, trust unitholders are owed
a fiduciary duty by the property trustee, but not by Ocean;
- trust unitholders have limited voting rights;
- trust unitholders are taxed on their allocable share of trust net income;
- trust unitholders are entitled to federal income tax depletion
deductions;
- substantially all trust income will be distributed to trust unitholders;
and
- trust assets are primarily limited to the net profits interests, which
have a finite economic life.
8
<PAGE> 12
RISK FACTORS
TRUST DISTRIBUTIONS WILL BE SENSITIVE TO CHANGING OIL AND NATURAL GAS PRICES
The trust's monthly cash distributions are highly dependent upon the prices
realized from the sale of natural gas. Oil and 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 Ocean. These factors include, among others:
- weather conditions;
- the supply and price of foreign oil and natural gas;
- the level of consumer product demand;
- worldwide economic conditions;
- political conditions in the Middle East and other oil-producing regions;
- the price and availability of alternative fuels;
- the proximity to, and capacity of, transportation facilities; and
- worldwide energy conservation measures.
Moreover, government regulations, such as regulation of natural gas
transportation and price controls, can affect product prices in the long term.
Lower oil and natural gas prices will reduce net profits to which the trust
is entitled and may ultimately reduce the amount of oil and natural gas that is
economic to produce from the underlying properties. The volatility of energy
prices reduces the accuracy of estimates of future cash distributions to trust
unitholders.
TRUST DISTRIBUTIONS ARE AFFECTED BY PRODUCTION AND DEVELOPMENT COSTS
Production and development costs on the underlying properties will be
deducted in the calculation of the trust's share of net proceeds. Accordingly,
higher or lower production and development costs will directly decrease or
increase the amount received by the trust for its net profits interests. For a
summary of these costs for the last three years, see "The Underlying
Properties -- Historical Results from the Underlying Properties."
If development and production costs of underlying properties located in a
particular state exceed the proceeds of production from the properties in that
state, the trust will not receive net proceeds for 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.
PRODUCTION RISKS CAN ADVERSELY AFFECT TRUST DISTRIBUTIONS
The occurrence of drilling, production or transportation disruptions at any
of the underlying properties will reduce trust distributions by the amount of
uninsured costs. For example, accidents may occur which result in personal
injuries, property damage, damage to productive formations or equipment and
environmental damages. Any uninsured costs would be deducted as a production
cost in calculating net proceeds payable to the trust.
TRUST RESERVE ESTIMATES ARE UNCERTAIN
The value of the trust units will depend upon, among other things, the
reserves attributable to the trust's net profits interests. Estimating reserves
is inherently uncertain. Ultimately, actual production, revenues and
expenditures for the underlying properties will vary from estimates and
9
<PAGE> 13
those variations could be material. Petroleum engineers consider many factors
and make assumptions in estimating reserves. Those factors and assumptions
include:
- historical production from the area compared with production rates from
other producing areas;
- the assumed effect of governmental regulation; and
- assumptions about future commodity prices, production, development and
transportation costs, severance and excise taxes, and capital
expenditures.
Changes in these assumptions can materially change reserve estimates.
The trust's reserve quantities and revenues are based on estimates of
reserve quantities 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 oil and natural gas reserves. See "The Underlying Properties -- Oil and
Natural Gas Reserves" for a discussion of the method of allocating proved
reserves to the trust.
THE TRUST DOES NOT CONTROL OPERATIONS AND DEVELOPMENT
Ocean is unable to significantly influence the operations or future
development of the underlying properties that it does not operate. The current
operators of the underlying properties, including Ocean, are under no obligation
to continue operating the properties. Ocean can sell any of the underlying
properties that it operates and relinquish its control of operations. Neither
the property trustee nor trust unitholders have the right to control or
influence operations on the underlying properties.
Working interest owners within the underlying properties, and owners of the
gathering and transportation systems upon which the underlying properties
depend, are not obligated to approve proposed system expansions.
OCEAN MAY TRANSFER OR ABANDON UNDERLYING PROPERTIES
Although it does not currently intend to sell any of the underlying
properties, Ocean may at any time transfer all or part of the underlying
properties. You will not be entitled to vote on any transfer, and the trust will
not receive any proceeds from 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. As a result, any excess costs
incurred by the transferee relating to the transferred property will not reduce
the net proceeds paid to the trust from the underlying properties retained by
Ocean. The transferee would be responsible for all of Ocean's obligations
relating to the net profits interests on the portion of the underlying
properties transferred, and Ocean would have no continuing obligation to the
trust for those properties.
Ocean or any transferee may abandon any well or property if it reasonably
believes that the well or property can no longer produce in commercially
economic quantities. This could result in termination of the net profits
interest relating to the abandoned well or property.
NET PROFITS INTERESTS CAN BE SOLD OR THE TRUST MAY BE DISSOLVED
The trustee must sell the net profits interests if the holders of 80% or
more of the trust units approve the sale or vote to dissolve the trust. The
trustee must also sell the net profits interests if the annual gross proceeds
from the underlying properties are less than $1 million for each of two
consecutive years after 1999. Sale of all the net profits interests will
dissolve the trust. The net proceeds of any sale will be distributed to the
trust unitholders.
10
<PAGE> 14
OCEAN HAS THE RIGHT TO OBTAIN ADDITIONAL TRUST UNITS
Ocean has the right to cause the trust to issue up to 9,333,310 additional
trust units in exchange for the conveyance of additional net profits interests
in the underlying properties. Any such conveyance will be at a fixed rate of
266,666 units per 1% net profits interest conveyed. If Ocean acquires additional
trust units through the conveyance of additional net profits interests to the
trust, Ocean will be able to exercise greater control over matters subject to
the vote of trust unitholders.
Ocean will have the right to cause the trust to either register the sale of
any additional trust units acquired by it under the federal securities laws or,
in the alternative, to directly sell all or a portion of the trust units and
deliver the net proceeds of the sale to Ocean, in each case subject to Ocean's
agreement with the underwriters not to sell any trust units until 180 days after
the date of this prospectus.
OCEAN'S DISPOSAL OF THE TRUST UNITS IT ACQUIRES FROM THE TRUST MAY REDUCE THE
TRUST UNIT MARKET PRICE
Following the offering, Ocean will own 3,000,000 trust units, or 1,650,000
trust units if the underwriters' over-allotment option is exercised in full. In
addition, Ocean has the option to acquire up to 9,333,310 additional trust units
after the offering in exchange for additional net profits interests in the
underlying properties. Ocean may use some or all of its trust units 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 Ocean sells trust units or exchanges trust units in connection with
acquisitions, the market price of the trust units may be reduced. Ocean has the
right to require the trust to register for sale any trust units owned by it
under the federal securities laws.
OCEAN MAY ENTER INTO CONTRACTS THAT ARE NOT NEGOTIATED IN ARM'S-LENGTH
TRANSACTIONS
Ocean and some of its affiliates receive payments under existing contracts
for services relating to the underlying properties. Payments to Ocean 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. These payments will include:
- reimbursements to Ocean for production and development costs to operate
wells;
- payments to Ocean's affiliates for gathering and transportation services,
which in the aggregate are designed to recover the costs of such
services; and
- overhead costs to operate the underlying properties, including
engineering, accounting and administrative functions, which Ocean expects
will be approximately $3.3 million in 2000.
Ocean believes that the terms of these arrangements are competitive with
those that could be obtained from unrelated third parties. Ocean is permitted
under the conveyance agreements creating the net profits interests to enter into
new marketing, processing and transportation contracts without any negotiations
or other involvement by independent third parties. Provisions in the conveyance
agreements, however, require that:
- future contracts with affiliates relating to marketing, processing or
transportation of oil and natural gas cannot materially exceed charges
prevailing in the area for similar services; and
11
<PAGE> 15
- future oil and natural gas sales contracts with affiliates must provide
that the affiliates retain not more than 2% of the proceeds from the sale
of production by the affiliates net of transportation and marketing
costs.
OCEAN MAY HAVE INTERESTS THAT ARE DIFFERENT FROM YOURS
Because Ocean has interests in oil and natural gas properties not included
in the trust, including properties located near the underlying properties, Ocean
may have interests that are different from yours. For example,
- in setting budgets for development and production expenditures for
Ocean's properties, including the underlying properties, Ocean may make
decisions that could adversely affect future production from the
underlying properties; these decisions could include reducing development
expenditures on underlying properties, which could cause natural gas
production to decline at a faster rate and result in lower future trust
distributions;
- Ocean 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 profits being available to trust unitholders; and
- Ocean 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, Ocean might sell some or all of the
underlying properties to a third party who could reduce development
expenditures on those properties, or Ocean could 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
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 Ocean and therefore will have no ability to influence its operations
of the underlying properties.
TRUST UNITHOLDERS WILL HAVE LIMITED ABILITY TO ENFORCE RIGHTS
The trust agreement permits the property trustee and the trust to sue Ocean
or any other future owner of the underlying properties to honor the net profits
interests. If the property trustee does not take appropriate action to enforce
provisions of the net profits interests, your recourse as a trust unitholder
would be limited to bringing a lawsuit against the property trustee to compel
the property trustee to take specified actions. You would not be able to sue
Ocean or any future owner of the underlying properties.
OCEAN'S LIABILITY TO THE TRUST IS LIMITED
The net profits interest conveyance provides that Ocean will not be liable
to the trust for the manner in which it performs its duties in operating the
underlying properties as long as it acts in good faith.
TRUST ASSETS ARE DEPLETING ASSETS
The net proceeds payable to the trust are derived from the sale of
depleting assets. Accordingly, the portion of the distributions to trust
unitholders attributable to depletion may be
12
<PAGE> 16
considered a return of capital. The reduction in proved reserve quantities is a
common measure of the depletion. Future maintenance and development projects on
the underlying properties will affect the quantity of proved reserves. The
timing and size of these projects will depend on the market prices of oil and
natural gas. If operators of the underlying properties do 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
Ocean. For federal income tax purposes, depletion is reflected as a deduction,
which is anticipated to be $ per trust unit in 2000, based on a trust unit
purchase price of $ . See "Federal Income Tax Consequences -- Tax
Treatment of Operations -- Royalty Income and Depletion."
AN IRS RULING WILL NOT BE REQUESTED
The availability to a trust unitholder of the federal income tax benefits
of an investment in the trust depends on the classification of the trust as a
partnership for federal income tax purposes. The trust has received an opinion
of tax counsel to the effect that the trust will be classified as a partnership
for federal income tax purposes. This means that:
- you will be taxed on your allocable share of the trust's net income,
regardless of whether you receive cash distributions from the trust; and
- you will be allowed depletion deductions equal to the greater of
percentage depletion or cost depletion, computed with respect to your pro
rata share of the trust's basis in the net profits interests. See
"Federal Income Tax Consequences."
Neither Ocean nor the property trustee has requested or is expected to
request a ruling from the IRS regarding any matter affecting the trust or the
trust unitholders. Neither Ocean nor the trust can assure you that they would be
granted such a ruling if requested. Moreover, there can be no assurance that the
law will not be changed so as to cause the trust to be treated as an association
taxable as a corporation for federal income tax purposes or otherwise subject to
entity-level taxation.
Trust unitholders should be aware of possible state tax implications of
owning trust units. See "State Tax Considerations."
THE TRUST'S NET PROFITS INTERESTS MAY NOT BE RESPECTED IN BANKRUPTCY
Although the matter is not entirely free from doubt, Ocean believes that
the net profits interests should constitute real property interests under
Arkansas, Montana and Oklahoma law. Ocean will record the conveyances in the
appropriate real property records of Arkansas, Montana and Oklahoma. If during
the term of the trust Ocean 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 Arkansas, Montana and Oklahoma. If a determination were made in a
bankruptcy proceeding that a net profits interest did not constitute a real
property 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, Ocean would not be required
to perform its obligations under the net profits interest and the trust would
seek damages as one of Ocean's unsecured creditors. Although no assurance can be
given, Ocean does not believe that the net profits interests should be subject
to rejection in a bankruptcy proceeding as executory contracts.
13
<PAGE> 17
FORWARD-LOOKING STATEMENTS
This prospectus contains or incorporates by reference "forward-looking
statements" within the meaning of Section 27A of the Securities Act, Section 21E
of the Exchange Act and the Private Securities Litigation Reform Act of 1995
about Ocean and the trust that are subject to risks and uncertainties. All
statements other than statements of historical fact included in this document,
including, without limitation, statements under "Prospectus Summary" and "Risk
Factors" regarding the financial position, business strategy, production and
reserve growth, and other plans and objectives for the future operations of
Ocean and the trust are forward-looking statements.
Such statements may be influenced by factors that could cause actual
outcomes and results to differ materially from those projected. Forward-looking
statements are subject to risks and uncertainties and include statements made in
this prospectus under "Projected Cash Distributions," statements pertaining to
future development activities and costs, and other statements in this prospectus
that are prospective and constitute forward-looking statements.
When used in this document, the words "believes," "expects," "anticipates,"
"intends" or similar expressions are intended to identify such forward-looking
statements. The following important factors, in addition to those discussed
elsewhere in this document and in the documents which are incorporated by
reference, could affect the future results of the energy industry in general,
and Ocean and the trust in particular, and could cause those results to differ
materially from those expressed in such forward-looking statements:
- risks incident to the drilling and operation of oil and gas wells;
- future production and development costs;
- the effect of existing and future laws and regulatory actions;
- the political and economic climate in the foreign jurisdictions in which
Ocean conducts oil and gas operations;
- the effect of changes in commodity prices, hedging activities and
conditions in the capital markets; and
- competition from others in the energy industry.
For additional information with respect to these factors, see "Where You
Can Find More Information." This document describes other important factors that
could cause actual results to differ materially from expectations of Ocean and
the trust, including under the heading "Risk Factors." All written and oral
forward-looking statements attributable to Ocean or the trust or persons acting
on behalf of Ocean or the trust are expressly qualified in their entirety by
such factors.
USE OF PROCEEDS
The trust will receive all proceeds from the sale of the trust units after
deducting underwriting discounts and the costs of the offering, which are
estimated to be $ assuming an initial public offering price of $
per unit. At completion of the offering, the trust will acquire the net profits
interests from Ocean in exchange for the payment by the trust to Ocean of all of
the net proceeds of this offering and the issuance by the trust to Ocean of
3,000,000 trust units. Ocean intends to apply the cash it receives from the
trust and from the sale of any units pursuant to the underwriters' overallotment
option to repay outstanding indebtedness under its existing revolving credit
facility. As of , 1999, Ocean owed $ million under the credit
facility. Amounts outstanding under the credit facility mature and
currently bear interest at an annual rate of %.
14
<PAGE> 18
OCEAN ENERGY, INC.
Ocean is one of the largest independent exploration and production
companies in the United States, primarily engaged in exploring for and producing
natural gas and crude oil. Ocean had total proved reserves of 2.98 Tcfe as of
December 31, 1998 on a pro forma basis, approximately 61% of which are natural
gas.
Ocean's North American operations are focused on the shelf and deepwater
areas of the Gulf of Mexico and in the Anadarko, Arkoma and Permian Basins, East
Texas and Rocky Mountain regions. Internationally, Ocean explores for and
produces oil and gas in West Africa, Egypt, Russia and Indonesia. In addition,
Ocean has exploration programs underway in Angola, Pakistan, Bangladesh and
Yemen. As of December 31, 1998, Ocean's acreage position comprised more than 40
million gross acres worldwide.
Ocean employs approximately 1,500 people and its principal executive
offices are located at 1001 Fannin, Suite 1600, Houston, Texas 77002. For more
information about Ocean, see "Where You Can Find More Information."
THE TRUST
The trust is a statutory business trust created under the Delaware Business
Trust Act in July 1999. Bank One, Texas, N.A., as property trustee, will be
responsible for trust administration. In addition, Bank One Delaware, Inc. will
act as Delaware trustee of the trust. The Delaware trustee will have only
minimal rights and duties as are necessary to satisfy requirements of the
Delaware Business Trust Act.
The property 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 provided the terms of the loan are 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 property trustee a fee of $ per year and a fee
of $ for services to dissolve the trust. The trust will pay the
Delaware trustee a fee of $ per year. The trust will also incur legal,
accounting and engineering fees, printing costs and other expenses that are
deducted from the 45% of net proceeds received by the trust before distributions
are made to trust unitholders. Total administrative expenses of the trust on an
annualized basis are expected to be approximately $ .
PROJECTED CASH DISTRIBUTIONS
Ocean will create the net profits interests through three conveyances to
the trust of 45% net overriding royalty interests, referred to in this
prospectus as net profits interests, carved from Ocean's interests in properties
in Arkansas, Montana and Oklahoma. The net profits interests will entitle the
trust to receive 45% of the net proceeds from the sale of natural gas
attributable to the underlying properties. Net proceeds equal the gross proceeds
received by Ocean from the sale of production less property and production
taxes, development, production, transportation and marketing costs and overhead.
For a more detailed description of net proceeds, see "Computation of Net
Proceeds."
The amount of trust revenues and cash distributions to trust unitholders
will depend primarily upon:
- natural gas prices;
- the volume of oil and natural gas produced and sold; and
- taxes and development, production, transportation and marketing costs and
overhead.
15
<PAGE> 19
2000 PROJECTED CASH DISTRIBUTIONS
The following table provides projected cash distributions to be received by
trust unitholders during the year 2000. The calculations assume realized prices
of $1.90 per Mcf of natural gas, which is based on an assumed $2.40 per MMBtu
NYMEX price, and assume sales volumes indicated in the reserve report. The
projections were prepared by Ocean as its best estimate of cash distributions to
trust unitholders during calendar year 2000 based on these pricing assumptions
and other assumptions that are described in "-- Significant Assumptions Used to
Prepare the 2000 Projected Cash Distributions." Ocean's independent auditors
have not examined, compiled or otherwise applied procedures to the projections
presented herein and, accordingly, do not express an opinion or any other form
of assurance on them. Because the trust does not receive cash with respect to
production from the underlying properties until approximately 60 days after the
end of the month in which it is produced, the projections are derived from an
estimate of production from October 1999 through September 2000. The projections
and the assumptions on which they are based are subject to significant
uncertainties, many of which are beyond the control of Ocean or the trust.
ACTUAL CASH DISTRIBUTIONS TO TRUST UNITHOLDERS DURING CALENDAR YEAR 2000,
THEREFORE, COULD VARY SIGNIFICANTLY BASED UPON CHANGES IN ANY OF THESE
ASSUMPTIONS. Cash distributions to trust unitholders will be particularly
sensitive to fluctuations in natural gas prices. See "-- Sensitivity of 2000
Projected Cash Distributions to Natural Gas Prices" which shows estimated
effects to cash distributions from changes in natural gas prices. As a result of
typical production declines for natural gas properties, production estimates
generally decrease from year to year. ACCORDINGLY, THE PROJECTED 2000 CASH
DISTRIBUTIONS ARE NOT NECESSARILY INDICATIVE OF DISTRIBUTIONS FOR FUTURE YEARS.
Because payments to the trust will be generated by depleting assets, a portion
of each distribution may represent a return of your original investment. See
"Risk Factors -- Trust Assets Are Depleting Assets."
<TABLE>
<CAPTION>
AMOUNT
---------------------
(IN THOUSANDS,
EXCEPT PER UNIT DATA)
<S> <C> <C>
Underlying Properties
Natural Gas Sales Volumes (Mcfe).............. 34,162
Natural Gas Assumed Sales Price (per Mcfe).... $ 1.90
Calculation of Distributable Income
Natural Gas Sales Revenues.................... $64,957
Costs:
Production and property taxes.............. 3,313
Production expenses........................ 4,479
Overhead................................... 3,324
Development costs.......................... 11,000
-------
Total................................. 22,116
-------
Net proceeds.................................. 42,841
Net profits percentage........................ 45%
-------
Trust royalty income.......................... 19,278
Trust administrative expense.................. 500
-------
Trust distributable income.................... $18,778
=======
</TABLE>
<TABLE>
<CAPTION>
CASH DISTRIBUTION
AS A PERCENTAGE OF
$ TRUST UNIT
PRICE
------------------
<S> <C> <C>
Per Trust Unit (12,000,000 Trust Units):........
Total cash distributions...................... $
Cost depletion tax deduction..................
-------
Taxable income................................
Income tax rate...............................
-------
Income tax expense............................
-------
Total cash distributions after tax............ $
=======
</TABLE>
16
<PAGE> 20
SENSITIVITY OF 2000 PROJECTED CASH DISTRIBUTIONS TO NATURAL GAS PRICES
Ocean prepared the following unaudited tables, which demonstrate the
estimated effect that changes in the prices for natural gas could have on trust
distributions. The following tables show:
- the projected cash distributions per trust unit for calendar year 2000;
- the resulting projected cash distributions per trust unit as a percentage
of the purchase price of the trust unit; and
- the resulting projected cash distributions 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 individual tax
rate of 39.6%.
THE TABLES 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 CASH DISTRIBUTIONS AND CASH DISTRIBUTIONS AS A
PERCENTAGE OF TRUST UNIT PURCHASE PRICE TO CHANGES IN THE PRICES OF NATURAL GAS.
THERE IS NO ASSURANCE THAT THE ASSUMPTIONS DESCRIBED BELOW 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 monthly cash
distributions from the trust is expected to vary during the year. Month-to-month
distributions will also vary based on the timing of development expenditures and
the net proceeds, if any, generated by development projects.
<TABLE>
<CAPTION>
NYMEX GAS PRICE PER MMBTU
-----------------------------
$2.25 $2.50 $2.75 $3.00
----- ----- ----- -----
<S> <C> <C> <C> <C>
Wellhead Gas Price per Mcf.................................. $1.75 $2.00 $2.25 $2.50
Sensitivity of Projected Total Cash Distributions Per Trust
Unit...................................................... 1.38 1.69 1.99 2.29
Sensitivity of Projected Pre-Tax Cash Distributions as a
Percentage of Trust Unit Price of $ ..................
Sensitivity of Projected After-Tax Cash Distributions as a
Percentage of Trust Unit Price of $ ..................
</TABLE>
SIGNIFICANT ASSUMPTIONS USED TO PREPARE THE 2000 PROJECTED CASH DISTRIBUTIONS
Timing of Actual Distributions. In preparing the 2000 projected cash
distributions and sensitivity tables above, the revenues and expenses of the
trust were calculated based on the terms of the conveyances creating the trust's
net profits interests. These calculations are described under "Computation of
Net Proceeds." Because net proceeds from production during October through
December in each year will in fact be distributed from the trust in the
following year, the cash distributions for 2000 represent projected cash
distributable income from the trust for production for the period from October
1999 through September 2000.
Production Estimates. Production estimates for 2000 are based on the
reserve report. The reserve report assumed constant prices at July 1, 1999,
based on the weighted average wellhead natural gas price at July 1, 1999 of
$1.68 per Mcf. Production from the underlying properties for 2000 is estimated
to be 34,162 MMcfe of natural gas. See "-- Natural Gas Prices" below for a
description of changes in production due to price variations. Sales for 1998 on
a cash basis were 33,779 MMcfe of natural gas. Differing levels of production
will result in different levels of distributions and cash returns.
Natural Gas Prices. Natural gas prices assumed in the 2000 projected cash
distributions estimate and shown in the tables are based on wellhead prices for
natural gas. The 2000 projected cash distributions estimate assumes wellhead
natural gas prices of $1.90 per Mcf. Wellhead price is the net price received
for natural gas after all deductions for transportation,
17
<PAGE> 21
marketing and gathering. The weighted average price of natural gas production
from the underlying properties during 1998 was $1.63 per Mcfe. This was
approximately $0.48 below the average of the monthly closing NYMEX natural gas
futures contract prices for the same period. However, if previously occurring
location, quality and other differentials continue in the future, 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 above tables
are based upon an analysis by Ocean of the historic price differentials for
production from the underlying properties with consideration given to gravity,
quality and transportation and marketing costs that may affect these
differentials in 2000. There is no assurance that these assumed differentials
will recur in 2000.
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 2000 production to reflect potential reductions or suspensions
of production.
Production Expenses and Taxes, Development Costs and Overhead. For 2000,
Ocean estimates production expenses and taxes to be $7.8 million, development
costs to be $11.0 million and overhead to be $3.3 million. Estimated overhead
reflects an increase in the number of active operated completions and a 5%
increase in overhead rates. For a description of production expenses and
development costs, see "Computation of Net Proceeds."
Administrative Expense. Trust administrative expense for 2000 is assumed to
be $ ($ per trust unit). See "The Trust."
Projected After-Tax Cash Distributions as a Percentage of Trust Unit Price
of $ . Because the net profits interests are depleting assets, a
portion of each distribution may be considered a return of your original
investment for federal income tax purposes. For a discussion of alternative ways
of measuring the depletion of oil and natural gas assets, see "Federal Income
Tax Consequences."
The Projected After-Tax Cash Distributions as a Percentage of Trust Unit
Price of $ were computed by:
- determining the amount of federal income tax that would be paid on the
cash distributions at the assumed highest individual effective tax rate
for 2000 of 39.6%, taking into account a cost depletion tax deduction of
$ per trust unit;
- subtracting this income tax amount from the annual cash distributions;
and
- dividing the result by $ per trust unit.
Cost depletion is calculated by multiplying the assumed trust unit purchase
price of $ by the cost depletion rate of %. This rate was estimated
by dividing estimated 2000 production by July 1, 1999 proved reserves estimated
in the reserve report. See "Federal Income Tax Consequences."
When the distributions are less than $ per trust unit, the Projected
After-Tax Cash Distributions as a Percentage of Trust Unit Price of $
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
implications have not been considered. The effect of state income taxes has not
been taken into account in computing the Projected After-Tax Cash Distributions
as a Percentage of Trust Unit Price of $ . See "State Tax
Considerations."
18
<PAGE> 22
THE UNDERLYING PROPERTIES
Ocean owns the underlying properties. Following the offering and the
conveyance by Ocean of the 45% net profits interest to the trust, Ocean will own
the underlying properties, subject to the net profits interests that will be
conveyed to the trust. Ocean may, at any time, sell all or any portion of the
underlying properties, subject to the net profits interests. It has no present
intention to do so.
Ocean's interests in the underlying properties include its undivided
interests in oil and natural gas leases and the production from existing and
future wells on those leases. Ocean's interests cover the leased acreage and
wells drilled on that acreage. When Ocean drills additional wells on the leased
acreage covered by its interests, or when it deepens or opens new producing
zones in existing wells, any production from those activities is attributable to
the underlying properties. Accordingly, those activities, if successful, will
increase or replace production from the underlying properties and increase
revenues subject to the trust's net profits interest.
Ocean's interest in substantially all of the underlying properties is
referred to in the oil and natural gas industry as a "working interest." A
working interest is an interest of an oil and natural gas lease entitling its
owner to receive a specified percentage of production, but requiring the owner
to bear the cost of exploring for, developing and producing oil and natural gas
from the property.
Where the working interest is held by a number of persons on a single
lease, a working interest owner is designated the lease operator by agreement.
Ocean operates approximately 88% of the underlying properties based on 1998
production, and established independent producers operate the rest. A lease
operator can significantly influence operations on the lease, including the
timing and amount of discretionary expenditures for operational and development
activities. For that reason it is desirable to operate properties, and it is
important that the operator be qualified and experienced.
DISCUSSION AND ANALYSIS OF HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES
The following table provides natural gas sales volumes, average sales
prices, revenues, direct operating expenses, development costs and overhead
relating to the underlying properties for each of the years ended December 31,
1996, 1997 and 1998 and the three months ended March 31, 1998 and 1999. See the
audited statements of revenues and direct operating expenses of the underlying
properties for the years ended December 31, 1996, 1997 and 1998 and the
unaudited statements of revenues and direct operating expenses of the underlying
properties for the three months ended March 31, 1998 and 1999 beginning on page
F-3 in this prospectus.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
--------------------------- -------------------
1996 1997 1998 1998 1999
------- ------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
Natural Gas Sales Volumes (Mcfe)......... 30,736 34,197 33,067 8,428 8,175
Natural Gas Average Prices (per Mcfe).... $ 2.10 $ 1.97 $ 1.63 $ 1.78 $ 1.46
Gas Sales Revenues....................... $64,557 $67,457 $54,048 $15,042 $11,929
Direct Operating Expenses:
Production and property taxes.......... 2,721 3,333 2,793 691 526
Production expenses.................... 5,017 5,239 5,785 1,579 1,412
------- ------- ------- ------- -------
Total.......................... 7,738 8,572 8,578 2,270 1,938
------- ------- ------- ------- -------
Excess of Revenues over Direct Operating
Expenses............................... $56,819 $58,885 $45,470 $12,772 $ 9,991
======= ======= ======= ======= =======
Development Costs........................ $ 8,623 $12,005 $15,183 $ 3,260 $ 691
======= ======= ======= ======= =======
Overhead................................. $ 2,153 $ 2,435 $ 2,831 $ 629 $ 756
======= ======= ======= ======= =======
</TABLE>
19
<PAGE> 23
Volumes. Natural gas sales volumes from the underlying properties increased
11% from 1996 to 1997 and decreased 3% from 1997 to 1998. The 1997 increase was
primarily due to additional reserves from development projects. The 1998
decrease was primarily due to normal production declines and curtailments in
Arkansas required because production in previous periods exceeded allowables.
Natural gas sales volumes from the underlying properties decreased 3% from the
first quarter of 1998 to the first quarter of 1999 due to normal production
declines.
Prices. The average price realized for natural gas decreased 6% from 1996
to 1997 and decreased 17% from 1997 to 1998. The average price realized for
natural gas declined 18% from $1.78 per Mcfe for the first quarter of 1998 to
$1.46 per Mcfe for the first quarter of 1999.
Direct operating expenses. Direct operating expenses increased 11% from
$7,738,000 in 1996 to $8,572,000 in 1997, primarily due to an increase in
production taxes associated with revenue increases. Direct operating expenses
remained constant at $8,578,000 in 1998 as an increase in workover expenses was
offset by declining production taxes. Direct operating expenses declined 15%
from the first quarter of 1998 to the first quarter of 1999, primarily due to
lower production taxes.
Development costs. Development costs increased from $8,623,000 in 1996 to
$12,005,000 in 1997 and $15,183,000 in 1998. Development costs decreased from
$3,260,000 for the first quarter of 1998 to $691,000 for the first quarter of
1999. Ocean expects development costs to be approximately $10 million to $11
million per year.
Overhead. Overhead charged to the underlying properties by Ocean was
$2,153,000 in 1996, $2,435,000 in 1997 and $2,831,000 in 1998, and was $629,000
for the three months ended March 31, 1998 and $756,000 for the three months
ended March 31, 1999. Fluctuations resulted from changes in the number of active
operated completions and an increase in overhead rates as a result of inflation.
PRODUCING ACREAGE AND WELL COUNTS
For the following data, "gross" refers to the total wells or acres on the
underlying properties in which Ocean owns a working interest and "net" refers to
gross wells or acres on the underlying properties multiplied by the percentage
working interest owned by Ocean.
The underlying properties are interests in developed properties located
primarily in natural gas producing regions of Arkansas, Montana and Oklahoma.
The following is a summary of the approximate producing acreage of the
underlying properties at July 1, 1999.
<TABLE>
<CAPTION>
GROSS NET
----------------------- -----------------------
DEVELOPED UNDEVELOPED DEVELOPED UNDEVELOPED
--------- ----------- --------- -----------
<S> <C> <C> <C> <C>
Arkoma Basin
Arkansas................................... 212,000 4,000 72,000 2,000
Oklahoma................................... 52,000 5,000 19,000 2,000
Bear Paw Area -- Montana..................... 182,000 114,000 147,000 96,000
------- ------- ------- -------
Total........................................ 446,000 123,000 238,000 100,000
======= ======= ======= =======
</TABLE>
As of July 1, 1999, the underlying properties contained 1,204 gross (724
net) natural gas producing wells. Of these natural gas producing wells, Ocean
operated 863 gross (650 net), and 341 gross (74 net) were not operated by Ocean.
20
<PAGE> 24
The following is a summary of the development wells drilled by Ocean on the
underlying properties during the last three years and for the six months ended
June 30, 1999.
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
------------------------------------------ JUNE 30,
1996 1997 1998 1999
------------ ------------ ------------ ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Productive..................... 36 17.0 56 44.9 81 63.6 29 23.6
Non-productive................. 11 6.6 17 10.7 18 16.0 11 8.1
-- ---- -- ---- -- ---- -- ----
Total................ 47 23.6 73 55.6 99 79.6 40 31.7
== ==== == ==== == ==== == ====
</TABLE>
NATURAL GAS SALES PRICES AND PRODUCTION COSTS
The following table shows the average sales prices per Mcfe of natural gas
produced and the production costs and production and property taxes per Mcfe for
the underlying properties:
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------ -------------
1996 1997 1998 1998 1999
------ ------ ------ ----- -----
<S> <C> <C> <C> <C> <C>
Natural gas sales prices (net of transportation
costs)............................................ $2.10 $1.97 $1.63 $1.78 $1.46
Production costs.................................... 0.16 0.15 0.17 0.19 0.17
Production and property taxes....................... 0.09 0.10 0.08 0.08 0.06
</TABLE>
OVERVIEW OF PRODUCING AREAS
The underlying properties consist of long-lived gas reserves in
northwestern Arkansas, eastern Oklahoma and north central Montana. The Arkoma
Basin has produced over 13 Tcf of natural gas since the early part of the 20th
century and is expected to produce beyond the year 2050. Since its discovery in
1966, the Bear Paw area has produced in excess of 500 Bcf of natural gas.
Arkoma Basin
Overview. The first commercially productive natural gas completion in the
Arkoma Basin was made in 1902, and almost 1.8 million productive acres have been
developed since. There are currently over 6,400 active completions in the Arkoma
Basin, with cumulative production of over 13 Tcf of natural gas and 980,000
barrels of oil. The underlying properties are concentrated in the Cecil and
Aetna Fields, primarily in Crawford, Franklin, Logan and Sebastian counties in
northwestern Arkansas and in the Ashland, Reams Northwest and Kinta Fields,
primarily in Coal, Pittsburg, Haskell and Le Flore counties in eastern Oklahoma.
The underlying properties also include interests in the Peter Pender,
Clarksville and Ewing Fields in Arkansas, as well as in various other fields.
Production occurs from sands ranging in depth from less than 1,000 feet to more
than 10,000 feet, with over 20 known producing zones. Ocean's projected 2000 net
daily production in the underlying properties in this area as derived from the
reserve report is approximately 53.7 MMcf per day.
Low Production Expenses. Arkoma Basin production is primarily dry, sweet
gas with minor amounts of water production. Typically, wells in this area
exhibit high productivity with low lifting costs because artificial lift and
fluid separation facilities are generally not required. Reduced wellhead
pressures via compression allow for significant increases in producing rates and
in the producing life of the wells.
Within major producing areas in the Arkoma Basin, acreage in the underlying
properties is concentrated in large blocks of contiguous leases, with Ocean
operating 65% of the existing wells on the underlying properties in Arkansas and
24% of the existing wells on the underlying
21
<PAGE> 25
properties in Oklahoma. Wells operated by Ocean account for 86% of the
discounted present value of estimated future net revenue and 86% of net
production in this area of the underlying properties.
These producing characteristics and the geographic concentration of
operated leases allow Ocean to centralize compression facilities to enhance
production and reserves while minimizing field personnel and compression
expenses. As Ocean operates a large percentage of these wells, Ocean has
additional control over the timing and amount of development expenditures,
including installation of compression.
Low Risk Reserves. Proved developed reserves account for 94% of the
discounted present value of estimated future net revenues on the underlying
properties in this area. Over 90% of the proved reserves associated with the
underlying properties in the Arkoma Basin are producing reserves requiring no
significant future capital expenditures.
Production. The Cecil and Aetna fields are the two largest gas fields in
Arkansas, and Ocean is the largest gas producer in these fields, as well as in
the state. Nearly 70% of Ocean's production in the underlying properties in the
Arkoma Basin is from the Cecil and Aetna fields. Current net production from
these properties exceeds 57 MMcf per day, with 86% of the net production from
wells operated by Ocean.
Production Operations. Ocean operates 378 gross wells in the underlying
properties in the Arkoma Basin and owns working interests in 300 additional
wells. Ocean's average working interest in the 678 wells is 45%, with a 63%
average working interest in the operated wells. Because of the stacked nature of
productive sands, 161 of the working interest wells are completed in two or more
zones, resulting in a total of 839 producing completions, 496 of which are
operated by Ocean. The use of dual, and sometimes triple, completions allows
accelerated production of reserves without having to drill additional wells or
wait many years for deeper completions to deplete before bringing the shallower
sands on production. Multiple completions also reduce capital and operating
costs relative to multiple wells.
Historical and Future Development Activity. Ocean has drilled or
participated in the drilling of 98 wells in the underlying properties in the
Arkoma Basin over the last three years. Although the Arkoma Basin is a mature
province, Ocean believes that the presence of multiple pay sands coupled with
complex faulting and stratigraphy should result in additional opportunities.
Ocean currently has 20 proved undeveloped locations scheduled for drilling
within the next 18 months. Estimated ultimate recovery from these locations
totals 12.2 Bcf based on planned capital expenditures of approximately $6.3
million, for a discounted present value of estimated future net revenue of $8.1
million. Identified drilling locations range from 2,500 to 10,000 feet in depth
at estimated gross drilling and completion costs per well of $225,000-$900,000.
Drilling costs in the Arkoma Basin are relatively inexpensive due primarily to
lower than normal pressures and lack of water bearing sands which allow wells to
be drilled with air rather than conventional drilling fluids. Ocean has also
identified 20 behind pipe recompletion opportunities with 2.3 Bcf of proved
reserves. Typical gross recompletion costs average $70,000 per recompletion.
As a result of scheduled development drilling and recompletions over the
next three years, net production from the underlying properties in this area is
expected to decline approximately 1% per year. Without a continuing development
program, production from the underlying properties in this area would normally
decline about 10% per year.
Compression Potential. Ocean's gas wells in the underlying properties in
the Arkoma Basin produce into gathering systems that operate at various
operating pressures. While production from specific wells is delivered at the
gathering systems' pressure, the producing reservoirs may benefit significantly
from lower pressures at the wellhead, accomplished through compression. Such
lower pressures may allow increased production and recoverable reserves. Ocean
believes that wells in its Aetna, Cecil and Kinta fields hold the greatest
potential to benefit from additional
22
<PAGE> 26
compression facilities, with approximately a third of company operated wells
standing to benefit. Within the past few months, Ocean has installed compression
on six wells in the Cecil and Aetna fields, and has increased net daily flow
rates by approximately 1.5 MMcf per day.
Cost Reduction Potential. Ocean's lifting costs for the underlying
properties in the Arkoma Basin are approximately $0.21 per Mcfe, which Ocean
believes is among the lowest in the region. In spite of this efficiency of
operations, Ocean has embarked on a company wide campaign to reduce field
operating costs. Several measures have already been implemented in the
underlying properties, which are expected to result in net annual savings of
approximately $150,000. Ocean believes that installation of new central point
compression facilities and efficiencies gained through field automation could
result in additional savings. These synergies have not been reflected in the
lease operating expense summaries or the reserve report.
Control of Natural Gas Gathering Systems. In the Aetna field, Ocean and its
working interest owners own and operate the gathering system allowing optimal
management of operations. In the remaining fields, Ocean's natural gas is
gathered primarily by a third party gathering company with which Ocean has a
long relationship.
Bear Paw Area
Overview. The underlying properties in the Bear Paw area consist of
long-lived gas reserves in north central Montana. Ocean's production from the
Bear Paw area, in north central Montana, makes Ocean the largest natural gas
producer in the state of Montana. Since discovery in 1966, the area has produced
in excess of 500 Bcf of natural gas primarily from the Cretaceous Eagle
formation at 1,200 to 2,000 feet. The underlying properties include
approximately 243,000 net acres in this area, with Ocean operating over 95% of
the underlying properties in the Bear Paw area. Ocean's projected 2000 net daily
production in the underlying properties in this area as derived from the reserve
report is approximately 39.1 MMcf of natural gas.
Low Production Expenses. Ocean's production in the underlying properties
consists of gas from unitized fields, non-unit fields, and Ocean operated and
non-operated properties. Approximately 95% of Bear Paw 2000 production is
expected to come from Ocean operated properties. The production is dry, sweet
gas with only minor amounts of water production. Consequently, the Bear Paw area
has a long history of low operating costs. Production expenses were $0.07 per
Mcf in 1996 and 1997 and $0.06 per Mcf in 1998.
Low Risk Reserves. Proved developed reserves account for 81% of the
discounted present value of estimated future net revenues on the underlying
properties in this area. Nearly 67% of the proved reserves associated with the
underlying properties in the Bear Paw area are producing reserves requiring no
significant future capital expenditures.
Production. Production from the underlying properties in the Bear Paw area
comprises gas production from the Bullhook and Tiger Ridge Units, as well as
non-unit production. Current net production from these properties exceeds 38
MMcf per day. Ocean is the largest gas producer in these fields, as well as in
the state of Montana. Continued exploration and development drilling has
increased Ocean's annual net gas production from 7.6 Bcf in 1996 to the current
projected production for 1999 of 13.7 Bcf.
Production Operations. Ocean operates 485 wells with an average working
interest of approximately 85% in the underlying properties in the Bear Paw area
and owns working interests in 41 additional wells. Remedial work to remove water
from wells that are carrying a fluid level has been an area of emphasis in 1999
and has shown encouraging results.
Historical and Future Development Activity. From 1996 through 1998, Ocean
drilled 121 wells in the Bear Paw area, expending approximately $7.5 million and
obtaining an 80% success rate for this three-year period. Ocean added 47.6 Bcf
of proved reserves at a finding and development cost of $0.16 per Mcf.
23
<PAGE> 27
Ocean currently has 134 proved undeveloped locations scheduled for drilling
within the next 18 months. Estimated ultimate recovery from these locations
totals 29.1 Bcf based on planned capital expenditures of approximately $9.2
million, for a discounted present value of estimated future net revenues of $7.2
million.
Over 325 well locations in this area have been identified and recognized by
the independent consultants (212 proved). During the first six months of 1999,
Ocean completed 25 of 34 gas wells drilled, establishing a 74% success rate.
Compression Potential. Ocean's gas wells produce into gathering systems
that operate at various pressures. Due to the high productivity of many of the
producing reservoirs, reduced wellhead pressures are critical to production
enhancement and reserve recovery. This makes gas compression an integral part of
the Bear Paw operation. Ocean, through its majority-owned subsidiary which
operates the Bear Paw gathering and transportation system, plans to increase the
compression in its Bear Paw properties beginning later this year. With
additional compression, wellhead pressures will be reduced, resulting in lower
abandonment pressures and higher reserve recoveries of natural gas per well.
Control of Natural Gas Gathering and Transportation Systems. Gas produced
from the Bear Paw area flows into a gathering and transportation system owned by
a majority-owned subsidiary of Ocean. Operation of this 500-mile pipeline and
compression system provides Ocean and other Bear Paw producers who are owners
the ability to effectively manage gathering, compression and transportation
fees, as well as flexibility in responding to system expansion, well connection
and maintenance needs of the pipeline. Also, Ocean holds firm transportation
rights on various pipelines, including the TransCanada Pipeline, which provides
significant transportation and marketing flexibility by allowing Ocean to access
major markets in the upper Midwestern United States. In addition to these
markets, Ocean sells gas in the Canadian and intrastate Montana markets. Ocean's
objective is to maximize wellhead netback value while maintaining marketing
flexibility.
OIL AND NATURAL GAS RESERVES
Miller and Lents estimated oil and natural gas reserves attributable to the
underlying properties as of July 1, 1999. 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.
Miller and Lents 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 Ocean 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 are calculated by subtracting from 45% of proved reserves of
the underlying properties, reserve quantities of a sufficient value to pay 45%
of the future estimated production and development costs, excluding overhead.
Accordingly, proved reserves for the net profits interests reflect quantities
that are calculated after reductions for future costs and expenses based on the
price and cost assumptions used in the reserve estimates.
The standardized measure of discounted future net cash flows and changes in
discounted cash flows presented below were prepared using assumptions required
by the Financial Accounting Standards Board. These assumptions include the use
of prices for oil and natural gas and costs for estimated future development and
production expenditures to produce the proved reserves, in each case as of July
1, 1999.
24
<PAGE> 28
Because natural gas prices are influenced by seasonal demand, use of July
1, 1999 prices, as required by the Financial Accounting Standards Board, 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%. There is no
provision for federal income taxes because future net revenues are not subject
to taxation at the trust level.
Proved Reserves
The following table shows proved reserves, proved developed reserves,
future net revenues and discounted present value of future net revenues at July
1, 1999 for the underlying properties, 45% of the underlying properties and the
net profits interests.
<TABLE>
<CAPTION>
45% OF
UNDERLYING UNDERLYING NET PROFITS
PROPERTIES PROPERTIES INTERESTS
---------- ---------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Proved natural gas reserves(Mcfe)......................... 339,170 152,627 113,037
Proved developed natural gas reserves(Mcfe)............... 274,368 123,466 96,749
Future net revenues....................................... $403,666 $181,826 $181,826
Present value discounted at 10% per annum................. $225,731 $101,690 $101,690
</TABLE>
The following table summarizes the changes in estimated proved reserves of
the underlying properties for the periods indicated.
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
--------------------------- JULY 1,
1996 1997 1998 1999
------- ------- ------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Proved Natural Gas Reserves (Mcfe):
Balance, beginning of period...................... 229,943 243,944 252,083 266,994
Revisions, extensions, discoveries and
additions.................................... 28,476 39,379 41,581 89,241
Purchases....................................... 16,261 2,957 6,397 0
Production...................................... (30,736) (34,197) (33,067) (17,065)
------- ------- ------- -------
Balance, end of period............................ 243,944 252,083 266,994 339,170
======= ======= ======= =======
Proved Developed Natural Gas Reserves (Mcfe):
Balance........................................... 218,822 227,880 234,413 274,368
</TABLE>
25
<PAGE> 29
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, 45% of
the underlying properties and the net profits interests as of July 1, 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>
45% OF
UNDERLYING UNDERLYING NET PROFITS
PROPERTIES PROPERTIES INTERESTS
---------- ---------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash flows......................................... $575,454 $258,954 $192,071
Future costs:
Production.............................................. 142,719 64,048 10,245
Development............................................. 29,069 13,080 --
-------- -------- --------
Future net cash flows..................................... 403,666 181,826 181,826
10% discount factor....................................... 177,935 80,136 80,136
-------- -------- --------
Standardized measure...................................... $225,731 $101,690 $101,690
======== ======== ========
</TABLE>
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
regulation of the terms, conditions and rates for interstate transportation,
storage 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.
Although natural gas prices are currently unregulated, Congress
historically has been active in the area of natural gas regulation. Ocean 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. Ocean 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. Those laws may impact operations of the
underlying properties. Ocean believes that it is in substantial compliance with
the environmental laws and regulations that apply to the operations of the
underlying properties. Ocean has not previously incurred material expenses in
complying with environmental laws and regulations that affect its operations of
the underlying properties. It does not currently expect that future compliance
will have a material adverse effect on the trust or the monthly distributions.
State Regulation. The various states regulate the production 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. States may regulate rates
of production and may establish maximum daily production allowables from both
oil and gas wells based on market demand or resource conservation, or both. The
effect of these regulations may be to limit the amounts of natural gas and oil
that may be produced from Ocean's wells, and to limit the number of wells or
locations Ocean can drill.
26
<PAGE> 30
Other Regulation. The Minerals Management Service of the United States
Department of Interior is evaluating existing methods of settling royalties on
federal and Native American oil and gas leases. Approximately 9% of the net
acres of the underlying properties, primarily those located in the Bear Paw
area, involve federal leases. Although the final rules could cause an increase
in the federal royalties to be paid on these properties and, correspondingly,
decrease the revenue to Ocean and the trust from these properties, Ocean does
not believe that the proposed rule changes will have a significant detrimental
effect on the distributions from the trust.
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.
Ocean does not believe that compliance with these laws will have a material
adverse effect upon the trust unitholders.
TITLE TO PROPERTIES
Ocean believes that its title to the underlying properties is, and the
trust's title to the net profits interest will be, good and defensible in
accordance with standards generally accepted in the oil and gas industry.
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;
- contractual obligations, including, in some cases, development
obligations and preferential rights of purchase, arising under operating
agreements, unit 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 commutation 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 Ocean's 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. Ocean believes that the burdens and obligations affecting the
underlying properties and the net profits interests are conventional in the
industry for similar properties. Ocean 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, Ocean believes that
the net profits interests should constitute real property interests under
Arkansas, Montana and Oklahoma law. Ocean will record the conveyances in the
appropriate real property records of Arkansas, Montana and Oklahoma. If during
the term of the trust Ocean or any successor 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 Arkansas, Montana and Oklahoma. If a determination were made in a bankruptcy
proceeding that a net profits interest did not constitute a real property
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
27
<PAGE> 31
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, Ocean would not be required to perform its obligations under the net
profits interest and the trust would seek damages as one of Ocean's unsecured
creditors. Although no assurance can be given, Ocean does not believe that the
net profits interests should be subject to rejection in a bankruptcy proceeding
as executory contracts.
MARKETING
Ocean's working interest share of natural gas production in the Arkoma
Basin is sold to a third party. This arrangement includes a monthly market index
price for the gas production plus a premium at various pooling points. Various
long-term gathering or compression agreements with third parties cover primarily
all of the underlying properties in Arkansas and Oklahoma.
Ocean's natural gas production from the Bear Paw area is served by a
gathering and transportation system owned by a majority-owned subsidiary of
Ocean. Ocean is a party to long-term gathering and compression agreements with
the subsidiary covering almost all of the underlying properties in Montana. Gas
is delivered from this system for sale to third parties in Montana, Canada and
the upper Midwest United States under short- or long-term agreements, depending
on market conditions.
The objective of sales from the underlying properties is to obtain the best
available price at the wellhead. If new contracts are entered into with
unaffiliated third parties, the proceeds from sales under those new contracts
will be included in gross proceeds from the underlying properties. The sales
price is net of any deductions for transportation from the wellhead to the
ultimate purchaser and any gravity or quality adjustments.
YEAR 2000
Historically, most computer systems (including microprocessors embedded
into field equipment and other machinery) utilized software that recognized a
calendar year by its last two digits. Beginning in the year 2000, these systems
will require modification to distinguish twenty-first century dates from
twentieth century dates.
Because Ocean operates most of the underlying properties, the trust is
dependent upon Ocean's Year 2000 readiness. Ocean has initiated a comprehensive
plan to address the Year 2000 issues associated with its operations and
business. Ocean's Board of Directors has been briefed about the Year 2000
problem generally and as it may affect Ocean. The Board has created a committee
consisting of senior executives and a representative from the Board to oversee
the adoption and implementation of the Year 2000 plan covering all of Ocean's
business units. The plan has been developed with an aim towards taking
reasonable steps to prevent Ocean's mission-critical functions from being
impaired due to the Year 2000 problem.
The plan includes several phases -- (a) assessment of all of Ocean's
systems and technology; (b) implementation and testing of modifications to or
replacements of existing systems and technology, both financial and operational;
(c) communication with key business partners regarding Year 2000 issues; and (d)
contingency planning.
In planning and developing the project, Ocean has considered both its
information technology ("IT") and its non-IT systems. The term "computer
equipment and software" includes systems that are commonly thought of as IT
systems, including accounting, data processing, telephone systems, scanning
equipment, and other miscellaneous systems. Non-IT systems include alarm
systems, fax machines, monitors for field operations, and other miscellaneous
systems. Both IT and non-IT systems may contain embedded technology, which
complicates Ocean's Year 2000 identification, assessment, remediation, and
testing efforts. In those cases where Ocean has identified equipment and
software that is not Year 2000 ready,
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Ocean is in the process of replacing or upgrading such items so they will
calculate dates correctly in the new century. Furthermore, as new equipment and
software are purchased in the ordinary course of business, Ocean ensures that
such purchases are Year 2000 ready.
During 1997, Ocean utilized both internal and external resources to test,
reprogram or replace many of its IT systems, primarily financial and operational
software, for necessary modifications identified in its assessment of Year 2000
issues. As of the date of this prospectus, Ocean has implemented its Year 2000
plan related to these IT systems, except for the reserves system which is
scheduled for the third quarter of 1999. During September 1998, Ocean began
utilizing internal and external resources to evaluate its vulnerability to Year
2000 issues related to its non-IT systems, primarily field operational systems
and equipment.
Ocean has employed outside engineering firms to inventory and evaluate
embedded chips in control, metering and monitoring devices on Ocean's producing
properties. Such devices are extensively used in offshore operations. While some
remedial work has been required, it was not extensive and is essentially
complete.
Ocean has also initiated formal communications with all of its key business
partners to determine the extent to which Ocean is vulnerable to those third
parties' potential failure to remediate their own Year 2000 issues. Key business
partners were identified in four categories of companies including: (a) major
vendors and contractors (including banks and other financial service companies);
(b) major customers; (c) utility companies; and (d) third party operators of
major oil and gas properties. Questionnaires were sent to Ocean's key business
partners to confirm their Year 2000 activities and follow-up letters, telephone
calls, and meetings are being used, as appropriate, to obtain additional
information.
During the fourth quarter of 1998, Ocean began developing contingency plans
for its financial and operational systems. Ocean's contingency plans are being
designed to minimize the disruptions or other adverse effects resulting from
Year 2000 incompatibilities regarding these systems, and to facilitate the early
identification and remediation of Year 2000 problems that first manifest
themselves after January 1, 2000.
The failure to correct a material Year 2000 issue could result in an
interruption in, or a failure of, certain normal business activities, resulting
in a material, adverse affect on Ocean's results of operations, liquidity and
financial position. Ocean's remediation efforts are expected to reduce
significantly Ocean's level of uncertainty about Year 2000 compliance and the
possibility of interruptions of normal operations. However, there can be no
guarantee that other companies' systems, on which Ocean's systems rely, will be
timely converted, or that a failure to convert by another company, or a
conversion that is incompatible with Ocean's systems, would not have a material
adverse effect on Ocean. Disruptions to the oil and gas transportation networks
controlled by third-party carriers could result in reduced production volumes
delivered to market.
In addition, risks associated with foreign operations may increase with the
uncertainty of Year 2000 compliance by foreign governments and their supporting
infrastructures. Ocean's Year 2000 task force members have been asked to
investigate the compliance activities of certain third parties and foreign
governments to determine the risks to Ocean. This investigation is in progress.
In a recent Securities and Exchange Commission release regarding Year 2000
disclosures, the Securities and Exchange Commission stated that public companies
must disclose the most reasonably likely worst case Year 2000 scenario. Analysis
of the most reasonably likely worst case Year 2000 scenarios Ocean may face
leads to contemplation of the following possibilities which, though unlikely in
some or many cases, must be included in any consideration of worst cases:
widespread failure of electrical, gas, and similar supplies by utilities serving
Ocean domestically and internationally; widespread disruption of the services of
communications common carriers domestically and internationally; similar
disruption to means and modes of
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transportation for Ocean and its employees, contractors, suppliers, and
customers; significant disruption to Ocean's ability to gain access to, and
remain working in, office buildings and other facilities; the failure of
substantial numbers of Ocean's mission-critical information (computer) hardware
and software systems, including both internal business systems and systems (such
as those with embedded chips) controlling operational facilities such as onshore
and offshore oil and gas rigs, oil and gas pipelines and gas plants domestically
and internationally, the effects of which would have a cumulative material
adverse impact on Ocean. Among other things, Ocean could face substantial claims
by customers or loss of revenues due to service interruptions, inability to
fulfill contractual obligations, inability to account for certain revenues or
obligations or to bill customers accurately and on a timely basis, and increased
expenses associated with litigation, stabilization of operations following
mission-critical failures, and the execution of contingency plans. Ocean could
also experience an inability by customers, traders, and others to pay, on a
timely basis or at all, obligations owed to Ocean. Under these circumstances,
the adverse effect on Ocean, and the diminution of Ocean's revenues, would be
material, although not quantifiable at this time. Any such adverse effects could
adversely affect the trust given the trust's significant reliance on Ocean with
respect to the underlying properties.
The trust's Year 2000 costs are not expected to be material.
COMPUTATION OF NET PROCEEDS
The provisions governing the computation of the net proceeds are detailed
and extensive. The following description of the net profits interests and the
computation of net proceeds is subject to and qualified by the more detailed
provisions of the conveyances of the net profits interests that are filed as
exhibits to the registration statement. See "Where You Can Find More
Information."
NET PROFITS INTERESTS
The net profits interests entitle the trust to receive 45% of the net
proceeds from the sale of natural gas produced from the underlying properties.
The amounts paid to the trust for the net profits interests are based on
the definitions of "gross proceeds" and "net proceeds" contained in the
conveyances and described below. Under the conveyances, net proceeds are
computed monthly. Ocean pays 45% of the aggregate net proceeds attributable to a
computation period to the trust on or before the last business day of the month
following the computation period. The computation period is the month following
the month of production. As a result, the trust does not receive cash with
respect to production from the underlying properties until approximately 60 days
after the end of the month in which it is produced and typically will not make
distributions to unitholders until the following month. Ocean will not pay to
the trust interest on the net proceeds held by Ocean prior to payment to the
trust. The property trustee makes distributions to trust unitholders monthly.
See "Description of the Trust Units -- Distributions and Income Computations."
Net proceeds equal the excess of gross proceeds over production costs and
excess production costs attributable to prior computation periods.
Gross proceeds means the amounts received by Ocean from sales of natural
gas produced from the underlying properties after deducting:
- all general property (ad valorem), production, severance, sales,
gathering, excise and other taxes and gathering costs if they are
deducted or excluded from the proceeds of sales of production; and
- any payment made to the owner of an underlying property for
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-- 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 such 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 does not include consideration for the transfer or sale of
any underlying property by Ocean or any subsequent owner to any new owner. Gross
proceeds also does not include any amount for natural gas lost in production or
marketing or used by the owner of the underlying properties in drilling,
production and plant operations. Gross proceeds includes payments for future
production if they are not subject to repayment in the event of insufficient
subsequent production.
Production costs means, on a cash basis, generally the sum of:
- all payments to mineral or landowners, 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 paid by the owner of an underlying property to the extent not
deducted in calculating gross proceeds, including estimated and accrued
ad valorem and other property taxes;
- costs paid by the owner of an underlying property under any joint
operating agreement;
- all other costs, expenses and liabilities of exploring for, drilling,
operating and producing natural gas, including allocated expenses such as
labor, vehicle and travel costs and materials;
- costs or charges associated with gathering, transporting, treating and
processing natural gas;
- certain interest costs;
- any overhead charge;
- 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.
As is customary in the oil and natural gas industry, Ocean charges an
overhead fee to operate the underlying properties. The operating activities
include various engineering, accounting and administrative functions. The fee is
based on a monthly charge per active operated completion, and it totaled
approximately $2.8 million in 1998 for all the underlying properties operated by
Ocean. The fee is customarily adjusted annually and will increase or decrease
each year based on changes in the year-end index of average weekly earnings of
crude petroleum and natural gas workers.
Excess production costs are the excess of production costs over gross
proceeds, plus interest accrued at the prime rate. Therefore, if production
costs exceed gross proceeds for a computation period, the trust will receive no
payment for that period, and excess production
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costs will be carried over to the following month as a production cost in
determining the excess of gross proceeds over production costs for that
following month.
Gross proceeds and production costs are calculated on a cash basis, except
that certain 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 will be created by three separate
conveyances, one for each of Arkansas, Montana and Oklahoma, the three states in
which the underlying properties are located. Net proceeds are calculated
separately for the underlying properties covered by each conveyance, so excess
production costs in one state do not reduce net proceeds from the others.
ADDITIONAL PROVISIONS
If a controversy arises as to the sales price of any production, then for
purposes of determining gross proceeds:
- amounts withheld or placed in escrow by a purchaser are not considered to
be received by the owner of the underlying property until actually
collected;
- amounts received by the owner of the underlying property and promptly
deposited with a nonaffiliated escrow agent will not be considered to
have been received until disbursed to it by the escrow agent; and
- amounts received by the owner of the underlying property and not
deposited with an escrow agent will be considered to have been received.
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 property trustee is not obligated to return
any income 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 Ocean recovers the overpayments
plus interest at the prime rate.
The conveyances permit Ocean to transfer without the consent or approval of
the trust unitholders all or any part of the underlying properties, subject to
the net profits interests. The trust unitholders are not entitled to any
proceeds of a transfer. 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. As a result, any excess costs generated from the transferred
property will not reduce the net proceeds paid to the trust from the underlying
properties retained by Ocean. The conveyances have been recorded in the
appropriate real property records to give notice of the net profits interests to
third parties, including Ocean's creditors and transferees.
As an operator of an underlying property, Ocean may enter into farmout,
operating, participation and other similar agreements to develop the property if
Ocean believes it to be advantageous to the working interest owners of the
property. The net profits interest held by the trust would then be calculated on
the interest retained by Ocean under the agreement and not on Ocean's original
interest before modification by the agreement. Ocean may enter into any of these
agreements without the consent or approval of the property trustee or any trust
unitholder. Ocean's interest in entering into any of these types of agreements,
however, should be parallel with that of trust unitholders because of Ocean's
retained interest in the underlying properties.
In addition, Ocean may require the trust to sell for cash net profits
interests that relate to underlying properties that Ocean is selling to an
unaffiliated party. In this case, the properties sold to the unaffiliated party
will no longer be subject to the net profits interests, but the trust will
receive its pro rata share of the proceeds from the sale of the properties.
Furthermore, sales made under this provision may not exceed in any calendar year
2% of the discounted present
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value of estimated future net revenues for the proved reserves of the underlying
properties allocated to the trust's net profits interests, as contained in the
most recent reserve report. This provision is designed to allow Ocean to dispose
of marginal properties that in most cases would not be contributing significant
net proceeds to the trust.
Ocean and any transferee of an underlying property will have the right to
abandon any well or property if it believes the well or property ceases to
produce or is not capable of producing in commercially paying quantities. Upon
termination of the lease, that portion of the net profits interests relating to
the abandoned property will be extinguished.
Ocean must maintain books and records sufficient to determine the amounts
payable for the net profits interests. Quarterly and annually, Ocean must
deliver to the property trustee a statement of the computation of the net
proceeds for each computation period. Ocean will cause the annual computation of
net proceeds to be audited. The audit cost will be borne by the trust.
FEDERAL INCOME TAX CONSEQUENCES
This section is a summary of material federal income tax considerations
that may be relevant to prospective trust unitholders and, to the extent set
forth below under "-- Legal Opinions and Advice," expresses the opinion of
Vinson & Elkins L.L.P., insofar as it relates to matters of law and legal
conclusions. This section is based upon current provisions of the Internal
Revenue Code of 1986, as amended (the "Code"), existing and proposed Treasury
regulations thereunder and current administrative rulings and court decisions,
all of which are subject to change at any time. Subsequent changes in such
authorities may cause the tax consequences to vary substantially from the
consequences described below. No attempt has been made in the following
discussion to comment on all federal income tax matters affecting the trust or
the trust unitholders. The following discussion is limited to trust unitholders
who will hold the trust units as "capital assets" within the meaning of the
Code. Moreover, the discussion focuses on trust unitholders who are individual
citizens or residents of the United States and has only limited application to
corporations, estates, trusts, non-resident aliens or other trust unitholders
subject to specialized tax treatment such as tax-exempt institutions, foreign
persons, IRAs, REITs or mutual funds. Prospective investors are urged to consult
their own tax advisors as to the particular tax consequences to them of the
ownership and disposition of an investment in trust units, including the
applicability of any federal income, federal estate or gift tax, state, local
and foreign tax laws, changes in applicable tax laws and any pending or proposed
legislation.
CLASSIFICATION OF THE TRUST AS A PARTNERSHIP
A partnership is not a taxable entity and incurs no federal income tax
liability. Instead, each partner is required to take into account his allocable
share of items of income, gain, loss, deduction and credit of the partnership in
computing his federal income tax liability, regardless of whether cash
distributions are made. Distributions to a partner generally are not taxable
unless the amount of any cash distributed is in excess of his adjusted basis in
his partnership interest.
An entity generally will be classified as a partnership rather than as a
corporation for federal income tax purposes if the entity (i) is treated as a
partnership under Treasury regulations, effective January 1, 1997, relating to
entity classification (the "Check-the-Box Regulations") and (ii) is not a
"publicly traded partnership" taxed as a corporation under Section 7704 of the
Code. In general, under the Check-the-Box Regulations, an unincorporated
domestic entity with at least two members may elect to be classified either as
an association taxable as a corporation or as a partnership. If such an entity
fails to make any election, it will be treated as a partnership for federal
income tax purposes.
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To be taxed as a partnership for federal income tax purposes, the trust, in
addition to qualifying as a partnership under the Check-the-Box Regulations,
must not be taxed as a corporation under Section 7704 of the Code dealing with
publicly-traded partnerships. The trust constitutes a "publicly-traded
partnership" within the meaning of Section 7704 of the Code. Section 7704 of the
Code provides that publicly-traded partnerships will, as a general rule, be
taxed as corporations. However, an exception (the "Qualifying Income Exception")
exists with respect to publicly-traded partnerships of which 90% or more of the
gross income for every taxable year consists of "qualifying income." Qualifying
income includes interest other than from a financial business, dividends and
income and gains from the exploration, development, mining or production,
processing, refining, transportation and marketing of any mineral or natural
resource.
In rendering its opinion set forth below, Vinson & Elkins L.L.P. has relied
on factual representations made by the trust and Ocean. Such factual matters are
as follows:
(a) The trust will not elect to be treated as an association taxable
as a corporation;
(b) The trust will be organized and operated in accordance with (i)
all applicable trust statutes, including the Delaware Business Trust Act,
(ii) the trust agreement, and (iii) the description thereof in this
prospectus; and
(c) For each taxable year, more than 90% of the gross income of the
trust will be income from sources that Vinson & Elkins L.L.P. has
heretofore opined or may hereafter opine is qualifying income within the
meaning of Section 7704(d) of the Code.
Based upon a review of the applicable legal authorities, Vinson & Elkins
L.L.P. is of the opinion that at least 90% of the trust's gross income is income
derived from the exploration, development, mining or production, processing,
refining, transportation or marketing of any mineral or natural resource or
other items of qualifying income, and, therefore, the trust will be classified
as a partnership for federal income tax purposes. Nonetheless, no assurance can
be given that the Qualifying Income Exception will be met in subsequent years.
If the trust fails to meet the Qualifying Income Exception other than an
inadvertent failure that is cured within a reasonable time, the trust will be
treated as if it had transferred all of its assets subject to its liabilities to
a newly formed corporation on the first day of the year in which it fails to
meet the Qualifying Income Exception in return for stock in that corporation,
and then distributed that stock to the partners in liquidation of their
interests in the trust. This contribution and liquidation should be tax-free to
trust unitholders and the trust, so long as the trust, at that time, does not
have liabilities in excess of the tax basis in its assets. Thereafter, the trust
would be treated as a corporation for federal income tax purposes.
If the trust were treated as an association taxable as a corporation in any
taxable year, either as a result of a failure to meet the Qualifying Income
Exception or otherwise, its items of income, gain, loss and deduction would be
reflected only on its tax return rather than being passed through to the trust
unitholders, and its net income would be taxed at the entity level at corporate
rates. In addition, any distribution made to a trust unitholder would be treated
as either taxable dividend income to the extent of the trust's current or
accumulated earnings and profits or, in the absence of earnings and profits, a
nontaxable return of capital to the extent of the trust unitholder's tax basis
in his trust units or taxable capital gain after the trust unitholder's tax
basis in the trust units is reduced to zero. Accordingly, treatment of the trust
as an association taxable as a corporation would result in a material reduction
in a trust unitholder's cash flow and after-tax return and, thus, would likely
result in a substantial reduction of the value of the trust units.
No ruling has been or will be requested from the IRS with respect to the
federal income tax treatment of the trust, including a ruling as to the status
of the trust as a partnership for federal income tax purposes. Thus, no
assurance can be provided that the opinions and statements set
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forth in this discussion of federal income tax consequences would be sustained
by a court if contested by the IRS.
The discussion below is based on the assumption that the trust will be
classified as a partnership for federal income tax purposes.
PARTNER STATUS
Trust unitholders should be treated as partners of the trust for federal
income tax purposes. A beneficial owner of trust units whose trust units have
been transferred to a short seller to complete a short sale would appear to lose
his status as a partner with respect to such trust units for federal income tax
purposes. See "-- Tax Treatment of Operations -- Treatment of Short Sales."
TAX CONSEQUENCES OF UNIT OWNERSHIP
Flow-through of Taxable Income
No federal income tax will be paid by the trust. Instead, each trust
unitholder will be required to report on his income tax return his allocable
share based on the percentage of trust units owned by that trust unitholder of
the income, gains, losses, deductions and credits of the trust without regard to
whether corresponding cash distributions are received by him. Consequently, the
trust may allocate income to trust unitholders even if they have not received a
cash distribution.
Treatment of Trust Distributions
Distributions by the trust to the trust unitholders generally will not be
taxable to the trust unitholder for federal income tax purposes to the extent of
his tax basis in his trust units immediately before the distribution. Cash
distributions in excess of that basis generally will be considered to be gain
from the sale or exchange of the trust units, taxable in accordance with the
rules described under "-- Disposition of Trust Units" below.
Basis of Trust Units
A trust unitholder's initial tax basis for his trust units will be the
amount he paid for the trust units. That basis will be increased by his share of
trust income and decreased (but not below zero) by distributions from the trust,
by the trust unitholder's share of trust losses and deductions, and by his share
of expenditures of the trust that are not deductible in computing its taxable
income and are not required to be capitalized. See "-- Disposition of Trust
Units -- Recognition of Gain or Loss."
Limitations on Deductibility of Trust Losses
The deduction by a trust unitholder of his share of trust losses may be
limited under the basis limitation, "at risk" rules and passive loss rules.
Special passive loss limitation rules apply with respect to publicly-traded
partnerships. It is not anticipated that the trust will generate losses.
Nevertheless, should losses result, trust unitholders must consult their own tax
advisors as to the applicability to them of such loss limitations.
Limitations on Interest Deductions
Generally, a non-corporate taxpayer's "investment interest expense" may be
deducted only to the extent of the taxpayer's "net investment income." Any
investment interest that is not deductible solely by reason of this limitation
may be carried forward to later taxable years and treated as investment interest
in such later years. In general, investment interest expense includes interest
on indebtedness properly allocable to property held for investment and the
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portion of interest expense paid or accrued on debt incurred or continued to
purchase or carry property held for investment. The computation of a trust
unitholder's investment interest expense will take into account interest on any
margin account borrowing or other loan incurred to purchase or carry trust
units. Net investment income includes gross income and certain net gain from
property held for investment and amounts treated as portfolio income pursuant to
the passive loss rules less deductible expenses other than interest directly
connected with the production of investment income.
ALLOCATION OF TRUST INCOME, GAIN, LOSS, DEDUCTION AND CREDIT
In general, items of trust income, gain, loss, deduction and credit will be
allocated among the trust unitholders in accordance with their respective
percentage interests in the trust, provided certain items of trust income, gain,
loss and deduction will be allocated to Ocean and the trust unitholders to
account for the difference between the tax basis and fair market value of
property contributed to the trust by Ocean or its affiliates. The effect of
these allocations to a trust unitholder will be essentially the same as if the
tax basis of the contributed property were equal to its fair market value at the
time of contribution.
TAX TREATMENT OF OPERATIONS
Accounting Method and Taxable Year
The trust will use the year ending December 31 as its taxable year and will
adopt the accrual method of accounting for federal income tax purposes. Each
trust unitholder will be required to include in income his allocable share of
trust income, gain, loss, deduction and credit for the taxable year of the trust
ending within or with the taxable year of the trust unitholder. In addition, a
trust unitholder who has a taxable year ending on a date other than December 31
and who disposes of all of his trust units following the close of the trust's
taxable year but before the close of his taxable year must include his allocable
share of trust income, gain, loss, deduction and credit in income for his
taxable year. As a result, he will be required to report in income for his
taxable year his distributive share of more than one year of trust income, gain,
loss, deduction and credit. See "-- Disposition of Trust Units -- Allocations
Between Transferors and Transferees."
Initial Tax Basis and Amortization
The initial tax basis of each net profits interest owned by the trust for
purposes of computing depletion for a trust unitholder will be effectively equal
to the fair market value of each net profits interest based on the portion of
the price paid for trust units allocable to each net profits interest.
Costs incurred in organizing the trust may be amortized over any period
selected by the trust not shorter than 60 months. The costs incurred in
promoting the issuance of trust units (i.e. syndication expenses) must be
capitalized and cannot be deducted currently, ratably or upon termination of the
trust. Substantially all of the costs incurred in connection with this offering
will be classified as syndication expenses, which may not be amortized.
Royalty Income and Depletion
Each net profits interest burdens multiple properties. 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 Code. The IRS is
presently taking the position that a 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 and the income
from the net profits interests will be royalty income qualifying for an
allowance for depletion. It would change this position if a different method
were established by the IRS or the courts.
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Each trust unitholder is entitled to a depletion allowance with respect to
each net profits interest. The deduction for depletion is determined annually
and is the greater of cost depletion or, if allowable, percentage depletion.
Percentage depletion is a statutory allowance equal to 15% of the gross income
from production from a property. Only trust unitholders who are not retailers or
refiners of oil, gas or products thereof will be entitled to claim percentage
depletion on the equivalent of 1,000 barrels of oil per day or less. 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.
Cost depletion is a unit-of-recovery method of cost recovery. 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. Ocean believes that trust unitholders who purchase trust units in this
offering will derive a substantially greater benefit from cost depletion than
from percentage depletion. Information will be provided to each trust unitholder
with respect to his allowable depletion deduction.
Section 754 Election
The trust intends to make the election permitted by Section 754 of the
Code. That election is irrevocable without the consent of the IRS. The election
will generally permit the trust to adjust a subsequent trust unit purchaser's
tax basis in the trust's assets pursuant to Section 743(b) of the Code to
reflect his purchase price. The Section 743(b)adjustment belongs to the
purchaser and not to other partners.
A Section 754 election is advantageous if the transferee's tax basis in his
units is higher than such trust units' share of the aggregate tax basis to the
trust of the trust's assets immediately prior to the transfer. In such a case,
as a result of the election, the transferee would have a higher tax basis in his
share of the trust's assets for purposes of calculating, among other items, his
depletion deduction and his share of any gain or loss on a sale of the trust's
assets. Conversely, a Section 754 election is disadvantageous if the
transferee's tax basis in such trust units is lower than such unit's share of
the aggregate tax basis of the trust's assets immediately prior to the transfer.
Thus, the fair market value of the trust units may be affected either favorably
or adversely by the election.
Treatment of Short Sales
A trust unitholder whose trust units are loaned to a "short seller" to
cover a short sale of trust units may be considered as having disposed of
ownership of those units. If so, he would no longer be a partner with respect to
those trust units during the period of the loan and may recognize gain or loss
from the disposition. As a result, during this period, any trust income, gain,
deduction, loss or credit with respect to those trust units would not be
reportable by the trust unitholder, any cash distributions received by the trust
unitholder with respect to those trust units would be fully taxable and all of
such distributions would appear to be treated as ordinary income. Trust
unitholders desiring to assure their status as partners and avoid the risk of
gain recognition should modify any applicable brokerage account agreements to
prohibit their brokers from borrowing their trust units.
DISPOSITION OF TRUST UNITS
Recognition of Gain or Loss
Gain or loss will be recognized on a sale of trust units equal to the
difference between the amount realized and the trust unitholder's tax basis for
the trust units sold.
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Gain or loss recognized by a trust unitholder, other than a "dealer" in
trust units, on the sale or exchange of a trust unit will generally be taxable
as capital gain or loss. Capital gain recognized on the sale of trust units held
for more than twelve months will generally be taxed at a maximum rate of 20%. A
portion of this gain or loss, which could be substantial, however, will be
separately computed and taxed as ordinary income or loss under Section 751 of
the Code to the extent attributable to depletion recapture. Ordinary income
attributable to depletion recapture may exceed net taxable gain realized upon
the sale of the trust unit and may be recognized even if there is a net taxable
loss realized on the sale of the trust unit. Thus, a trust unitholder may
recognize both ordinary income and a capital loss upon a disposition of trust
units. Net capital loss may offset no more than $3,000 of ordinary income in the
case of individuals and may only be used to offset capital gain in the case of
corporations.
The IRS has ruled that a partner who acquires interests in a partnership in
separate transactions at different prices must combine those interests and
maintain a single adjusted tax basis. Upon a sale or other disposition of less
than all of such interests, a portion of that tax basis must be allocated to the
interests sold using an "equitable apportionment" method. The ruling is unclear
as to how the holding period of these interests is determined once they are
combined. If this ruling is applicable to the holders of trust units, a trust
unitholder will be unable to select high or low basis trust units to sell as
would be the case with corporate stock. It is not clear whether the ruling
applies to the trust because, similar to corporate stock, interests in the trust
are evidenced by separate certificates.
Allocations Between Transferors and Transferees
In general, the trust's taxable income and losses will be determined
annually, will be prorated on a monthly basis and will be subsequently
apportioned among the trust unitholders in proportion to the number of trust
units owned by each of them as of the opening of the principal national
securities exchange on which the trust units are then traded on the first
business day of the month. A trust unitholder who owns trust units at any time
during a quarter and who disposes of such trust units prior to the record date
set for a cash distribution with respect to such quarter will be allocated items
of trust income, gain, loss, deductions and credit attributable to such quarter
but will not be entitled to receive that cash distribution.
Notification Requirements
A trust unitholder who sells or exchanges trust units is required to notify
the trust in writing of that sale or exchange within 30 days after the sale or
exchange and in any event by no later than January 15 of the year following the
calendar year in which the sale or exchange occurred. The trust is required to
notify the IRS of that transaction and to furnish certain information to the
transferor and transferee. However, these reporting requirements do not apply
with respect to a sale by an individual who is a citizen of the United States
and who effects the sale or exchange through a broker. Additionally, a
transferee of trust units will be required to furnish a statement to the IRS,
filed with its income tax return for the taxable year in which the sale or
exchange occurred, that sets forth the amount of the consideration paid for the
trust unit. Failure to satisfy these reporting obligations may lead to the
imposition of substantial penalties.
Constructive Termination
The trust will be considered to have been terminated if there is a sale or
exchange of 50% or more of the total interests in trust capital and profits
within a 12-month period. A termination of the trust will result in the closing
of the trust's taxable year for all trust unitholders. In the case of a trust
unitholder reporting on a taxable year other than a fiscal year ending December
31, the closing of the trust's taxable year may result in more than 12 months'
taxable income or loss of the trust being includable in his taxable income for
the year of termination. New tax elections required to be made by the trust,
including a new election under Section 754 of the Code, must
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be made subsequent to a termination, and a termination could result in a
deferral of trust deductions for depreciation. A termination could also result
in penalties if the trust were unable to determine that the termination had
occurred.
TAX-EXEMPT ORGANIZATIONS
Employee benefit plans and most other organizations exempt from federal
income tax including IRAs and other retirement plans are subject to federal
income tax on unrelated business taxable income. Because all of the income of
the trust is expected to be royalty income, none of which is unrelated business
taxable income, such organization exempt from federal income tax is not expected
to be taxable on income generated by ownership of trust units so long as the
trust units are not debt-financed property within the meaning of Section 514(b)
of the Code. In general, a trust unit would be debt-financed 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.
A regulated investment trust or "mutual fund" is required to derive 90% or
more of its gross income from interest, dividends, payments with respect to
securities loans, gains from the sale of stocks or securities or foreign
currency or certain related sources. It is not anticipated that any significant
amount of the trust's gross income will include that type of income.
TAXATION OF FOREIGN HOLDERS
Unless the election described below is made to be taxed on a net basis, a
foreign holder, that is, a nonresident alien individual, foreign corporation, or
foreign estate or trust, will be subject to withholding of federal income 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.
Trust unitholders who are foreign holders may elect under 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. A foreign holder who makes
such election would then be taxed at regular federal income tax rates on the net
income attributable to the net profits interests. In addition, absent a treaty
exception, the net income of a corporate foreign holder that has made such an
election will also be subject to the branch profits tax imposed under Section
884. 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.
Gain realized on a sale of a trust unit by a foreign holder will be subject
to federal income tax only if (i) the gain is otherwise effectively connected
with business conducted by the foreign holder in the United States, (ii) the
foreign holder is an individual who is present in the United States for at least
183 days in the year of the sale, (iii) a foreign holder owns more than a 5%
interest in the trust, or (iv) 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.
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ADMINISTRATIVE MATTERS
Trust Information Returns and Audit Procedures
The trust intends to furnish to each trust unitholder, within 90 days after
the close of each calendar year, certain tax information, including a Schedule
K-1, which sets forth each trust unitholder's share of the trust's income, gain,
loss, deduction and credit for the preceding trust taxable year.
The federal income tax information returns filed by the trust may be
audited by the IRS. Adjustments resulting from any such audit may require each
trust unitholder to adjust a prior year's tax liability, and possibly may result
in an audit of the trust unitholder's own return. Any audit of a trust
unitholder's return could result in adjustments of non-trust as well as trust
items.
Partnerships generally are treated as separate entities for purposes of
federal tax audits, judicial review of administrative adjustments by the IRS and
tax settlement proceedings. The tax treatment of partnership items of income,
gain, loss, deduction and credit are determined in a partnership proceeding
rather than in separate proceedings with the partners. The Code provides for one
partner to be designated as the "Tax Matters Partner" for these purposes. The
trust agreement appoints Ocean as the Tax Matters Partner of the trust.
The Tax Matters Partner will make certain elections on behalf of the trust
and trust unitholders and can extend the statute of limitations for assessment
of tax deficiencies against trust unitholders with respect to trust items. The
Tax Matters Partner may bind a trust unitholder with less than a 1% profits
interest in the trust to a settlement with the IRS unless that trust unitholder
elects, by filing a statement with the IRS, not to give such authority to the
Tax Matters Partner. The Tax Matters Partner may seek judicial review (by which
all the trust unitholders are bound) of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek judicial review, such
review may be sought by any trust unitholder having at least a 1% interest in
the profits of the trust and by the trust unitholders having in the aggregate at
least a 5% profits interest. However, only one action for judicial review will
go forward, and each trust unitholder with an interest in the outcome may
participate.
A trust unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is not consistent
with the treatment of the item on the trust's return. Intentional or negligent
disregard of the consistency requirement may subject a trust unitholder to
substantial penalties.
Registration as a Tax Shelter
The Code requires that "tax shelters" be registered with the Secretary of
the Treasury. The temporary Treasury regulations interpreting the tax shelter
registration provisions of the Code are extremely broad. It is arguable that the
trust is not subject to the registration requirement on the basis that it will
not constitute a tax shelter. However, Ocean, as a principal organizer of the
trust, has applied for registration of the trust as a tax shelter with the
Secretary of the Treasury in the absence of assurance that the trust will not be
subject to tax shelter registration and in light of the substantial penalties
which might be imposed if registration is required and not undertaken. ISSUANCE
OF THE REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN THE TRUST OR
THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.
The trust must furnish the registration number to the trust unitholders,
and a trust unitholder who sells or otherwise transfers a trust unit in a
subsequent transaction must furnish the registration number to the transferee.
The penalty for failure of the transferor of a trust unit to furnish the
registration number to the transferee is $100 for each such failure. The trust
unitholders must disclose the tax shelter registration number of the trust on
Form 8271 to be attached to the tax return on which any income, gain, loss,
deduction or credit of the trust is
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included. A trust unitholder who fails to disclose the tax shelter registration
number on his return, without reasonable cause for that failure, will be subject
to a $250 penalty for each failure. Any penalties discussed herein are not
deductible for federal income tax purposes. Registration as a tax shelter may
increase the risk of an audit.
Accuracy-Related Penalties
An additional tax equal to 20% of the amount of any portion of an
underpayment of tax which is attributable to one or more of certain listed
causes, including negligence or disregard of rules or regulations, substantial
understatements of income tax and substantial valuation misstatements, is
imposed by the Code. No penalty will be imposed, however, with respect to any
portion of an underpayment if it is shown that there was a reasonable cause for
that portion and that the taxpayer acted in good faith with respect to that
portion.
Certain more stringent rules apply to "tax shelters," a term that in this
context does not appear to include the trust. In addition, the trust will make
reasonable effort to furnish sufficient information for trust unitholders to
make adequate disclosure on their returns to avoid liability for any such
penalty attributable to ownership of the trust units.
STATE TAX CONSIDERATIONS
The following is a brief summary of the material state income taxes and
other state tax matters affecting the trust and the trust unitholders. The
following discussion focuses on trust unitholders who are individual citizens or
residents of the United States. Trust unitholders are urged to consult their own
legal and tax advisors as these matters relate to their individual
circumstances.
INCOME TAX CONSIDERATIONS
Trust unitholders may be subject to taxation by their state of residence on
income derived from the trust. Furthermore, Oklahoma, Arkansas, and Montana
impose income taxes on residents and, for certain types of income, nonresidents.
The property trustee will provide information concerning the trust
sufficient to identify the income of the trust allocable to each state. Trust
unitholders should consult their own tax advisors to determine their income tax
filing requirements for their share of trust income allocable to states imposing
an income tax.
Oklahoma
The income tax law of Oklahoma is based on federal income tax laws.
Assuming the trust is taxed as a partnership for federal income tax purposes,
the trust unitholders will be subject to Oklahoma income tax on their share of
income from the Oklahoma net profits interests. Trust unitholders who are
nonresidents of Oklahoma generally will not be taxed in that state on gains from
the sale of trust units.
Arkansas
Trust unitholders will be subject to Arkansas income tax on the income they
receive from the trust which is allocable to Arkansas properties. Trust
unitholders who are nonresidents of Arkansas generally will not be taxed in that
state on gains from the sale of trust units.
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Montana
Trust unitholders will be subject to Montana income tax on the income they
receive from the trust which is allocable to Montana properties. It is uncertain
whether trust unitholders who are nonresidents of Montana will be taxed in that
state on gains from the sale of trust units.
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 Arkansas, Oklahoma
and Montana. If the trust units are held to be real property or an interest in
real property under the laws of those states, the trust units may be subject to
devolution, probate and administration and estate taxes under the laws of those
states.
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ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended, 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. The Department of Labor has 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. Ocean
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 was filed as an exhibit to the
registration statement. See "Where You Can Find More Information."
CREATION AND ORGANIZATION OF THE TRUST; AMENDMENTS
Ocean will create the net profits interests and, at the closing of the
offering, will convey them to the trust in exchange for $ in cash and
trust units. Conveyance of the net profits interests will be effective
as of , 1999.
The trust was created under Delaware law to acquire and hold the net
profits interests for the benefit of the trust unitholders pursuant to an
agreement between Ocean, the property
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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. Neither Ocean nor other operators of the underlying
properties have any contractual commitments to the trust to conduct further
drilling on or to maintain their ownership interest in any of these properties.
For a description of the underlying properties and other information relating to
them, see "The Underlying Properties."
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 80% 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.
Certain amendments do not require the vote of trust unitholders.
RIGHT OF OCEAN TO ACQUIRE ADDITIONAL TRUST UNITS
Upon completion of the offering, the trust will have issued 12,000,000
trust units, 3,000,000 of which will be owned by Ocean, assuming no exercise of
the underwriters' over-allotment option. Under the trust agreement, Ocean will
have the right at any time to reduce its retained interest in the underlying
properties by conveying additional net profits interests in the underlying
properties to the trust in exchange for additional trust units. Any additional
trust units will be issued at the fixed rate of 266,666 units for each
additional 1% of net profits interest conveyed, which is the same ratio as the
initial trust units bear to the initial net profits interests conveyed to the
trust. The total additional net profits interests in the underlying properties
conveyed to the trust will not exceed 35%.
Ocean will be required to make any such conveyance of additional net
profits interest effective as of the first day of the second full month
preceding the issuance of the new trust units to account for the delay that
would otherwise result in attributing increased payments from the new net
profits interest to the trust units. Ocean will have the right to cause the
trust to either register the sale of any additional units acquired by it under
the federal securities laws or, in the alternative, to directly sell all or a
portion of the units at a price determined by Ocean and deliver the net proceeds
of the sale to Ocean.
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 and
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, except as modified by the trust agreement.
The property trustee's principal duties consist of:
- collecting income attributable to the net profits interests;
- paying expenses, charges and obligations of the trust from the trust's
income and assets;
- distributing distributable income to the trust unitholders; and
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- 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 distribution until the borrowed funds are repaid.
Each month, the property trustee will pay trust obligations and expenses
and distribute to the trust unitholders the remaining proceeds 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;
- money market funds that invest only in United States government
securities;
- repurchase agreements secured by interest-bearing obligations of the
United States government; 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 Ocean, the property trustee must sell for cash net
profits interests relating to the underlying properties sold by Ocean to an
unaffiliated third party. However, these sales are required only if in any
calendar year the net profits interests sold do not exceed 2% of the discounted
present value of estimated future net revenues for the proved reserves of the
trust's net profits interests, as contained in the most recent reserve report.
The property trustee may sell the net profits interests in any of the
following circumstances:
- the sale does not involve a material part of the trust's assets 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 constitutes a material part of the trust's assets and is in the
best interests of the trust unitholders and holders representing 80% 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
property trustee will distribute the net proceeds from any sale of the net
profits interests to the trust unitholders.
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
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character of the net profits interests in such a way that the net profits
interests become working interests or that the trust becomes an operating
business.
LIABILITIES OF THE TRUST
Because the trust does not conduct an active business and the property
trustee has little power to incur obligations, Ocean expects that the trust will
only incur liabilities for routine administrative expenses. These might include
the property trustee's fees and accounting, engineering, legal and other
professional fees.
RESPONSIBILITIES AND LIABILITIES OF THE 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.
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. See
"-- Duties and Limited Powers of the Trustee," above. The trust agreement,
however, provides that the property trustee may:
- charge for its services as property 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
- seek reimbursement from the trust for its out-of-pocket expenses.
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 trustee. The
property trustee is entitled to indemnification from trust assets or, to the
extent that trust assets are insufficient, from Ocean. Trust unitholders will
not be liable to the property trustee for any indemnification. See "Description
of the Trust Units -- Liability of Trust Unitholders." The property trustee must
ensure that all contractual liabilities of the trust are limited to the assets
of the trust and will be liable for its failure to do so.
DURATION OF THE TRUST; SALE OF NET PROFITS INTERESTS
The trust will dissolve if:
- the trust sells all of the net profits interests;
- annual gross proceeds attributable to the underlying properties are less
than $1 million for each of two consecutive years after 1999;
- the holders of 80% or more of the outstanding trust units vote in favor
of dissolution; or
- judicial dissolution of the trust.
The property trustee would then sell all of the trust's assets, either by
private sale or public auction, and distribute the net proceeds of the sale to
the trust unitholders.
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DISPUTE RESOLUTION
Any dispute, controversy or claim that may arise between Ocean and the
property trustee relating to the trust will be submitted to binding arbitration
before a tribunal of three arbitrators.
COMPENSATION OF THE PROPERTY TRUSTEE AND DELAWARE TRUSTEE
The property trustee's and Delaware trustee's compensation will be paid out
of the trust's assets. 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 the
expert.
DESCRIPTION OF THE TRUST UNITS
Each trust unit is a unit of beneficial interest in the trust and
represents an undivided 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 12,000,000 trust
units outstanding upon completion of the offering. In addition, Ocean has the
right to require the trust to issue an additional 9,333,310 units in exchange
for the conveyance of additional net profits interests in the underlying
properties to the trust. See "Description of the Trust Agreement." Ocean intends
to grant its executive officers options to purchase up to $ million of its
trust units at the initial public offering price. The executive officers will
not receive any trust distributions until their options are exercised.
DISTRIBUTIONS AND INCOME COMPUTATIONS
Each month, 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 month, over the trust's liabilities for that month. 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 at the
close of business on the monthly record date, which is the last business day of
the month, will receive a pro-rata distribution no later than 10 business days
after the monthly record date. It is expected that the first distribution on the
trust units will be paid in 1999.
Unless otherwise advised by counsel or the IRS, the property trustee will
treat the income and expenses of the trust for each month as belonging to the
trust unitholders of record on the monthly record date. Trust unitholders will
recognize income and expenses for tax purposes in the month the trust receives
or pays those amounts, rather than in the month the trust distributes them.
Minor variances may occur. For example, the property trustee could establish a
reserve in one month that would not result in a tax deduction until a later
month. The property trustee could also make a payment in one month that would be
amortized for tax purposes over several months. See "Federal Income Tax
Consequences."
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 owner of any trust
unit as shown by its records
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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 monthly record date will not
be entitled to the distribution relating to that monthly record date. Delaware
law will govern all matters affecting the title, ownership or transfer of trust
units.
PERIODIC REPORTS
The property trustee will mail to trust unitholders quarterly reports
showing the assets, liabilities, receipts and disbursements of the trust for
each quarter except the fourth quarter. 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 quarterly and annually reports that trust unitholders need to
correctly report their share of the income and deductions of the trust.
Each trust unitholder and his representatives may examine, for any proper
purpose, 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-election of the property trustee.
The property trustee or trust unitholders owning at least 10% of the
outstanding trust units may call meetings of trust unitholders. Meetings must be
held in Houston, 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.
Unless otherwise required by 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 80% of
the outstanding trust units is required to:
- dissolve the trust;
- amend the trust agreement (except with respect to certain matters that do
not adversely affect the right of trust unitholders in any 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 dissolution of the trust or
limited sales directed by Ocean 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 income Corporations are taxed on their
tax; trust unitholders are subject income, and their stockholders are
to income tax on their allocable taxed on dividends.
shares of trust net income, adjusted
for tax deductions.
Distributions Substantially all trust income is Stockholders receive dividends at
distributed to trust unitholders. the discretion of the board of
directors.
Business and Interest is limited to specific A corporation conducts an active
Assets assets with a finite economic life. business for an unlimited term and
can reinvest its earnings and raise
additional capital to expand.
Fiduciary Duties To the extent provided in the trust Officers and directors have a
agreement, the property trustee has fiduciary duty of loyalty to
a fiduciary duty to the trust stockholders and a duty to use due
unitholders. care in management and
administration of a corporation.
</TABLE>
LEGAL MATTERS
Richards, Layton & Finger, P.A., Wilmington, Delaware, as special Delaware
counsel to Ocean, will give a legal opinion as to the validity of the trust
units. Vinson & Elkins L.L.P., Houston, Texas, will give opinions as to certain
other matters relating to the offering, including the tax opinion described in
the section of this prospectus captioned "Federal Income Tax Consequences."
Counsel for the underwriters, Andrews & Kurth L.L.P., Houston, Texas, will give
a legal opinion to the underwriters regarding other matters related to this
offering.
EXPERTS
The statements of revenues and direct operating expenses of the underlying
properties of Ocean Energy Royalty Trust have been audited by KPMG LLP,
independent certified public accountants. The financial statements of Ocean
(formerly named Seagull Energy Corporation) incorporated by reference in this
prospectus have also been audited by KPMG LLP. These financial statements are
incorporated by reference herein in reliance upon their report and upon their
authority as experts in accounting and auditing.
Arthur Andersen LLP, independent public accountants, have audited the
financial statements of Ocean Energy, Inc., a Delaware corporation ("Old
Ocean"), incorporated by reference in this prospectus and elsewhere in the
registration statement. These financial statements are incorporated by reference
herein in reliance upon their report and upon their authority as experts in
giving that report.
Certain information appearing in this prospectus regarding the December 31,
1998 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 is based on estimates of the
49
<PAGE> 53
reserves and present values prepared by or derived from estimates prepared by
Miller and Lents, Ltd., independent petroleum engineers.
Certain information with respect to the oil and gas reserves associated
with Ocean's oil and gas properties derived from the reports of the following
independent petroleum engineers:
- DeGolyer and MacNaughton;
- McDaniel & Associates Consultants, Ltd.;
- Netherland, Sewell & Associates, Inc; and
- Ryder Scott Company Petroleum Engineers
has been included and incorporated herein by reference upon the authority of
said firms as experts with respect to the matters covered by their respective
reports.
WHERE YOU CAN FIND MORE INFORMATION
The trust and Ocean 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. In addition, Ocean files annual, quarterly and current reports, proxy
statements and other information with the SEC. You may read and copy the
registration statement and any of Ocean's reports, statements 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. Ocean's filings are also available to
the public on the SEC Internet Web site at http://www.sec.gov.
Bank One, Texas, N.A. is property trustee of the trust. The property
trustee's address is 910 Travis, 5th Floor, Houston, Texas 77002, Attention
Global Corporate Trust Services, and its telephone number is (713) 751-6834.
The SEC allows Ocean to "incorporate by reference" the information Ocean
files with them, which means that Ocean can disclose important information to
you by referring you to those documents. The information incorporated by
reference is an important part of this prospectus, and information that Ocean
files later with the SEC will automatically update and supersede this
information.
Because Ocean recently went through a major business combination, one of
the SEC filings from Old Ocean, is also incorporated by reference. On March 30,
1999, Old Ocean was merged into Ocean, which was then known as Seagull Energy
Corporation. At the same time, Ocean also amended its Articles of Incorporation
to change its name to "Ocean Energy, Inc." In the merger, each outstanding share
of Old Ocean common stock was exchanged for one share of Seagull Energy
Corporation common stock, and as of March 30, 1999, the stockholders of Old
Ocean owned approximately 61.5% of Ocean's outstanding common stock, with the
shareholders of Seagull Energy Corporation owning the remaining 38.5% of Ocean's
outstanding common stock. For accounting purposes, the merger was treated as an
acquisition of Seagull Energy Corporation by Old Ocean in a purchase business
transaction. Therefore, under generally accepted accounting principles, the
historical financial statements of Old Ocean are now Ocean's historical
financial statements.
50
<PAGE> 54
Ocean incorporates by reference the documents listed below and any future
filings made with the SEC under Section 13(a), 13(c), 14 or 15(d) of the
Securities Exchange Act of 1934 until Ocean sells all of the securities
described in this prospectus.
- Ocean's Annual Report on Form 10-K for the fiscal year ended December 31,
1998, filed with the SEC on February 16, 1999.
- The amendment to Ocean's Annual Report on Form 10-K/A for the fiscal year
ended December 31, 1998, filed with the SEC on March 1, 1999.
- Ocean's Quarterly Report on Form 10-Q for the quarter ended March 31,
1999, filed with the SEC on May 17, 1999.
- Old Ocean's Annual Report on Form 10-K for the fiscal year ended December
31, 1998, filed with the SEC on February 16, 1999.
- Ocean's Current Reports on Form 8-K, filed with the SEC on March 12,
1999, April 9, 1999, May 4, 1999, May 21, 1999, and June 23, 1999.
You may request a copy of these filings (other than an exhibit to a filing
unless that exhibit is specifically incorporated by reference into that filing)
at no cost, by writing or telephoning Ocean at the following address:
Ocean Energy, Inc.
1001 Fannin, Suite 1600
Houston, Texas 77002
Attention: Investor Relations
(713) 265-6000
You should rely only on the information incorporated by reference or
provided in this prospectus. Ocean has not authorized anyone else to provide you
with different information. Ocean is only offering these securities in states
where the offer is permitted. You should not assume that the information in this
prospectus is accurate as of any date other than the date on the front of this
document.
51
<PAGE> 55
GLOSSARY OF CERTAIN 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 standard cubic feet of natural gas.
Bcfe -- One billion standard 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 Revenues -- Also referred to as "estimated future net
cash flows." 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. Estimated
future net revenues do not include the effects of the tight sands natural gas
tax credit, since the trust is not a taxable entity and the credit goes directly
to the trust unitholders.
MBbl -- One thousand Bbl.
Mcf -- One thousand standard cubic feet of natural gas.
Mcfe -- One thousand standard cubic feet of natural gas equivalent,
computed on an approximate energy equivalent basis that one Bbl equals six Mcf.
MMBtu -- One million British Thermal Units (Btus).
MMcf -- One million standard cubic feet of natural gas.
MMcfe -- One million standard 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 Oil and Natural Gas Wells or Acres -- Determined by multiplying "gross"
oil and natural gas wells or acres by the interest in such wells or acres
represented by the underlying properties.
Net Profits 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.
NYMEX -- New York Mercantile Exchange, where futures and options contracts
for the oil and natural gas industry and some precious metals are traded.
Oil Revenue -- Includes revenue related to the sale of oil and condensate
production.
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.
52
<PAGE> 56
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 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.
(i) 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.
(ii) 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.
(iii) 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 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.
53
<PAGE> 57
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 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.
Tcf -- One trillion standard cubic feet of natural gas.
Tcfe -- One trillion standard cubic feet equivalent, which is determined
using the ratio of 1 Bbl of oil to 6 Mcf of natural gas.
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.
54
<PAGE> 58
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....... F-3
Notes to Financial Statements............................. F-4
Unaudited Statements of Revenues and Direct Operating
Expenses for the Three Months Ended March 31, 1998 and
1999................................................... F-8
Notes to Unaudited Financial Statements................... F-9
OCEAN ENERGY ROYALTY TRUST:
Unaudited Pro Forma Statement of Distributable Income for
the Three Months Ended March 31, 1999.................. F-12
Unaudited Pro Forma Statement of Distributable Income for
the Year Ended December 31, 1998....................... F-13
Unaudited Pro Forma Statement of Assets and Trust Corpus
as of March 31, 1999................................... F-14
Notes to Unaudited Pro Forma Financial Statements......... F-15
</TABLE>
F-1
<PAGE> 59
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Ocean Energy, Inc.:
We have audited the accompanying statements of revenues and direct
operating expenses of the Underlying Properties of Ocean Energy, Inc. and
subsidiaries for each of the years in the three-year 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.
The accompanying statements of revenues and direct operating expenses were
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission for inclusion in Form S-1 of the Ocean Energy
Royalty Trust as described in Note 1 and are not intended to be a complete
financial presentation.
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 years in the three-year period ended December 31,
1998 in conformity with generally accepted accounting principles.
KPMG LLP
Houston, Texas
July 12, 1999
F-2
<PAGE> 60
UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1996 1997 1998
------- ------- -------
<S> <C> <C> <C>
Revenues.................................................... $64,557 $67,457 $54,048
Direct Operating Expenses:
Production and property taxes............................. 2,721 3,333 2,793
Production expenses....................................... 5,017 5,239 5,785
------- ------- -------
7,738 8,572 8,578
------- ------- -------
Excess of Revenues over Direct Operating Expenses........... $56,819 $58,885 $45,470
======= ======= =======
</TABLE>
See accompanying notes to financial statements.
F-3
<PAGE> 61
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION
The Underlying Properties are predominantly working interests in producing
properties currently owned by Ocean Energy, Inc. and subsidiaries (the
"Company") in the Arkoma Basin of Oklahoma and Arkansas and the Bear Paw area in
Montana. The Company intends to convey 45% defined net profits interests ("Net
Profits Interests") in the Underlying Properties to the Ocean Energy Royalty
Trust (the "Trust") upon completion of the offering of the Trust units.
The Company's present ownership of the Underlying Properties is primarily a
result of two separate merger transactions which occurred in 1998 and 1999. 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 are presented on the accrual basis of accounting before the effects of
conveyance of the Net Profits Interests. The statements do not include
depreciation, depletion and amortization, general and administrative overhead or
interest expenses. Preparation of the statements requires the use of estimates,
judgments and assumptions that affect the reported amounts of revenues and
expenses during the reported periods. Actual results can differ from these
estimates.
If the Trust had been in place during the three years ended December 31,
1998, royalty income would have been based on the defined 45% net profits
interest percentage of net proceeds (revenues less direct operating expenses,
development costs and overhead) of the Underlying Properties. Net proceeds to
the Trust for the year ended December 31 are computed based on cash receipts and
disbursements for production from November of the prior year through October.
The computation also includes deductions for development costs on the properties
of $8,623,000, $12,005,000 and $15,183,000 in 1996, 1997 and 1998, respectively,
and overhead charges on the properties of $2,153,000, $2,435,000 and $2,831,000
in 1996, 1997 and 1998, respectively. Accordingly, royalty income of the Trust
will be materially different from the excess of revenues over direct operating
expenses from the Underlying Properties.
Revenues in the accompanying statements of revenues and direct operating
expenses are recognized following the entitlements method of accounting for
production.
3. RELATED PARTY TRANSACTIONS
From January 1, 1996 through June 30, 1998, the Company sold approximately
70% of the natural gas production from the Underlying Properties to certain of
the Company's wholly owned subsidiaries, generally at amounts approximating
monthly spot market prices, less transportation and fuel charges. Subsequent to
June 30, 1998, all production from the Underlying Properties was sold to third
parties. Approximately 30% of the production from the Underlying Properties is
transported through a gathering and transportation system operated by a
majority-owned subsidiary of the Company which charges fees designed to cover
the costs of such services.
4. CONTINGENCIES
The Company is a defendant in two separate lawsuits that could, if
adversely determined, decrease future revenues from certain of the Underlying
Properties. Any payments made in connection with these two lawsuits relating to
production prior to the formation of the Trust will be borne by the Company.
F-4
<PAGE> 62
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
A class action lawsuit, Anne K. Barnaby, individually and on behalf of all
others similarly situated, v. Seagull Mid-South Inc., was filed on April 23,
1996 in the District Court for Latimer County, Oklahoma. This class action was
brought on by the Plaintiff for herself as a representative of, and on behalf
of, certain other mineral owners in Oklahoma. The plaintiffs allege that since
1990 the Company has underpaid certain of its royalty owners as a result of
reducing royalties for improper charges for production, marketing, gathering,
processing and transportation costs. The plaintiffs are seeking an accounting
and payment of the monies allegedly owed to them. A similar class action
lawsuit, John T. Holleman et al. v. UMC Petroleum Corporation, was filed on
August 22, 1996 in the District Court of Dewey County, Oklahoma. The Company
believes that it has strong defenses to these lawsuits and intends to vigorously
defend its position. However, if a judgment or settlement increased the amount
of future royalty payments, revenues from the Underlying Properties will be
reduced. The amount of any reduction in such revenues is not presently
determinable, but, in management's opinion, is not expected to be material to
the Trust's distributable income.
Other -- The Underlying Properties are subject to other ongoing litigation
in the normal course of business. While the outcome of lawsuits or other
proceedings against the Company cannot be predicted with certainty, the Company
believes that the effect on excess of revenues over direct operating expenses,
if any, will not be material.
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The reserve volumes presented are estimates only and should not be
construed as being exact quantities. These reserves may or may not be recovered
and may increase or decrease as a result of future operations and changes in
economic conditions. The reserve estimates and standardized measure of
discounted future net cash flows provided for the Underlying Properties are
before the effects of conveying the defined net profits interest to the Trust.
PROVED RESERVES
<TABLE>
<CAPTION>
NATURAL GAS
---------------------------
1996 1997 1998
------- ------- -------
<S> <C> <C> <C>
Beginning of year........................................... 229,943 243,944 252,083
Revisions of previous estimates........................... 13,865 12,686 16,496
Purchases................................................. 16,261 2,957 6,397
Extensions and discoveries................................ 14,611 26,693 25,085
Production................................................ (30,736) (34,197) (33,067)
------- ------- -------
End of year................................................. 243,944 252,083 266,994
======= ======= =======
</TABLE>
PROVED DEVELOPED RESERVES
<TABLE>
<CAPTION>
NATURAL GAS
(MMCF)
-----------
<S> <C>
December 31, 1996........................................... 218,822
December 31, 1997........................................... 227,880
DECEMBER 31, 1998........................................... 234,413
</TABLE>
F-5
<PAGE> 63
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The Underlying Properties' standardized measure of discounted future net
cash flows as of December 31, 1997 and 1998 and the changes therein for each of
the years 1996, 1997 and 1998 are provided based on the present value of future
net revenues from proved oil and gas reserves estimated by independent petroleum
engineers in accordance with guidelines established by the Securities and
Exchange Commission. These estimates are computed by applying appropriate
year-end prices for natural gas to estimated future production of proved natural
gas reserves over the economic lives of the reserves and assuming continuation
of existing operating conditions. Year-end calculations were made using prices
of $3.48, $2.31 and $1.97 per thousand cubic feet of gas ("Mcf") for 1996, 1997
and 1998, respectively. Because the disclosures are standardized, significant
changes can occur in these estimates based upon gas prices in effect at
year-end. The following estimates should not be viewed as an estimate of fair
market value.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1997 1998
-------- --------
<S> <C> <C>
Future cash inflows......................................... $581,232 $526,519
Future development costs.................................... 8,155 10,546
Future production costs..................................... 119,525 122,436
-------- --------
Future net cash flows....................................... 453,552 393,537
10% annual discount......................................... 167,483 160,428
-------- --------
Standardized measure of discounted future net cash flows.... $286,069 $233,109
======== ========
</TABLE>
F-6
<PAGE> 64
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1996 1997 1998
-------- -------- --------
<S> <C> <C> <C>
Beginning of Year......................................... $185,656 $435,051 $286,069
Revisions of previous quantity estimates less related
costs................................................ 24,806 14,369 15,764
Extensions and discoveries less related costs........... 34,408 33,330 23,032
Net changes in future prices and production costs....... 204,815 (164,126) (53,038)
Purchases of reserves in place.......................... 25,152 3,012 5,099
Development costs incurred during the period............ 8,623 12,005 15,183
Sales of oil and gas produced, net of production
costs................................................ (56,819) (58,885) (45,470)
Accretion of discount................................... 18,566 43,505 28,607
Changes in production, timing and other................. (10,156) (32,192) (42,137)
-------- -------- --------
249,395 (148,982) (52,960)
-------- -------- --------
End of Year............................................... $435,051 $286,069 $233,109
======== ======== ========
</TABLE>
F-7
<PAGE> 65
UNDERLYING PROPERTIES
UNAUDITED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
-------------------
1998 1999
-------- --------
<S> <C> <C>
Revenues.................................................... $15,042 $11,929
Direct Operating Expenses:
Production and property taxes............................. 691 526
Production expenses....................................... 1,579 1,412
------- -------
2,270 1,938
------- -------
Excess of Revenues over Direct Operating Expenses........... $12,772 $ 9,991
======= =======
</TABLE>
See accompanying notes to unaudited financial statements.
F-8
<PAGE> 66
UNDERLYING PROPERTIES
NOTES TO UNAUDITED FINANCIAL STATEMENTS
1. ORGANIZATION
The Underlying Properties are predominantly working interests in producing
properties currently owned by Ocean Energy, Inc. and subsidiaries (the
"Company") in the Arkoma Basin of Oklahoma and Arkansas and the Bear Paw field
in Montana. The Company intends to convey 45% defined net profits interests
("Net Profits Interests") in the Underlying Properties to the Ocean Energy
Royalty Trust (the "Trust") upon completion of the offering of the Trust units.
The Company's present ownership of the Underlying Properties is primarily a
result of two separate merger transactions which occurred in 1998 and 1999. The
accompanying statements include the historical revenues and direct operating
expenses from these acquired properties for all periods 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 are presented on the accrual basis of accounting before the effects of
conveyance of the Net Profits Interests. The statements do not include
depreciation, depletion and amortization, general and administrative overhead or
interest expenses. Preparation of the statements requires the use of estimates,
judgments and assumptions that offset the reported amounts of revenues and
expenses during the reported periods. Actual results can differ from these
estimates.
The statements have been prepared, without audit, pursuant to the rules and
regulations of the Securities and Exchange Commission. The statements reflect
all normal recurring adjustments that, in the opinion of management, are
necessary for a fair presentation.
If the Trust had been in place during the three months ended March 31, 1998
and 1999, royalty income would have been based on the defined 45% net profits
interest percentage of net proceeds (revenues less direct operating expenses,
development costs and overhead) of the Underlying Properties. Net proceeds to
the Trust for the period ended March 31 are computed based on cash receipts and
disbursements for production from November of the prior year through January.
The computation also includes deductions for development costs on the properties
of $3,260,000 and $691,000 for the three months ended March 31, 1998 and 1999,
respectively, and overhead charges on the properties of $629,000 and $756,000
for the three months ended March 31, 1998 and 1999, respectively. 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
In the first quarter of 1998, the Company sold approximately 70% of the
natural gas production from the Underlying Properties to certain of the
Company's wholly owned subsidiaries, generally at amounts approximating monthly
spot market prices. In the first quarter of 1999, all production was sold to
various third parties. Approximately 30% of the production from the Underlying
Properties is transported through a gathering and transportation system operated
by a majority-owned subsidiary of the Company which charges fees designed to
cover such services.
4. CONTINGENCIES
The Company is a defendant in two separate lawsuits that could, if
adversely determined, decrease future revenues from certain of the Underlying
Properties. Any payments made in
F-9
<PAGE> 67
connection with these two lawsuits relating to production prior to the formation
of the Trust will be borne by the Company.
A class action lawsuit, Anne K. Barnaby, individually and on behalf of all
others similarly situated, v. Seagull Mid-South Inc., was filed on April 23,
1996 in the District Court for Latimer County, Oklahoma. This class action was
brought on by the Plaintiff for herself as a representative of, and on behalf
of, certain other mineral owners in Oklahoma. The plaintiffs allege that since
1990 the Company has underpaid certain of its royalty owners as a result of
reducing royalties for improper charges for production, marketing, gathering,
processing and transportation costs. The plaintiffs are seeking an accounting
and payment of the monies allegedly owed to them. A similar class action
lawsuit, John T. Holleman et al. v. UMC Petroleum Corporation, was filed on
August 22, 1996 in the District Court of Dewey County, Oklahoma. The Company
believes that it has strong defenses to these lawsuits and intends to vigorously
defend its position. However, if a judgment or settlement increased the amount
of future royalty payments, revenues from the Underlying Properties will be
reduced. The amount of any reduction in such revenues is not presently
determinable, but, in management's opinion, is not expected to be material to
the Trust's distributable income.
Other -- The Underlying Properties are subject to other ongoing litigation
in the normal course of business. While the outcome of lawsuits or other
proceedings against the Company cannot be predicted with certainty, the Company
believes that the effect on excess of revenues over direct operating expenses,
if any, will not be material.
F-10
<PAGE> 68
OCEAN ENERGY ROYALTY TRUST
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Ocean Energy Royalty Trust ("Trust") was created in July 1999 by Ocean
Energy, Inc. (the "Company"). Upon the completion of the offering, the Company
intends to convey net profits interests ("Net Profits Interests") in the
Underlying Properties to the Trust in exchange for 3,000,000 units of beneficial
interest in the Trust and the cash received by the Trust upon the offering of
9,000,000 trust units to the public, after offering expenses.
The pro forma statements of distributable income of the Trust for the three
months ended March 31, 1999 and the year ended December 31, 1998 have been
prepared from the historical statement of revenues and direct operating expenses
of the Underlying Properties, adjusted to the cash basis, and based on the
following assumptions:
- The Trust was formed and the Net Profits Interests were conveyed to the
Trust prior to November 1, 1997.
- Net proceeds related to the Net Profits Interests are received and
recorded as royalty income by the Trust in the month following their
receipt by the Company from the Underlying Properties. Generally, the
Trust will receive and record royalty income two months after the month
of production. This basis for recognizing royalty income differs from
generally accepted accounting principles which require that revenues be
accrued in the month of production.
- Royalty income is calculated based on 45% of the Net Proceeds from the
Underlying Properties. Net Proceeds is a defined term in the Net Profits
Interests' conveyances to the Trust.
- Administrative expense is estimated to be $500,000 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, reserve engineers,
printing and mailing.
- As a grantor trust, the Trust will not be required to pay federal income
taxes. Accordingly, the accompanying pro forma financial statements do
not include a provision for federal income taxes.
The pro forma statement of assets and trust corpus as of March 31, 1999 are
prepared as if the Net Profits Interests were conveyed at March 31, 1999 in
consideration for the issuance by the Trust of 3,000,000 trust units to Ocean
and the net proceeds from the offering.
The unaudited pro forma financial statements are not necessarily indicative
of the results of operations which would have occurred had the Trust been formed
prior to November 1, 1997, nor are they necessarily indicative of future results
of operations. The unaudited pro forma financial statements should be read in
conjunction with the historical financial statements of the Underlying
Properties, the Trust and the Company included, or incorporated by reference, in
this document.
F-11
<PAGE> 69
OCEAN ENERGY ROYALTY TRUST
UNAUDITED PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME
FOR THE THREE MONTHS ENDED MARCH 31, 1999
(AMOUNTS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
UNDERLYING
PROPERTIES OTHER COSTS CASH BASIS PRO FORMA
---------- ----------- ---------- ---------
(A) (B)
<S> <C> <C> <C> <C>
Revenues.......................................... $11,929 $2,247 $14,176
Direct Operating Expenses:
Production and property taxes................... 526 459 985
Production expenses............................. 1,412 (35) 1,377
------- -------
Total........................................... 1,938 2,362
------- -------
Excess of revenues over direct operating
expenses........................................ $ 9,991 11,814
=======
Development costs................................. $691 691
Overhead.......................................... 756 756
-------
Net proceeds............................................................................. 10,367
Net profits percentage................................................................... 45%
-------
Trust royalty income..................................................................... 4,665
Administrative expense................................................................... 125
-------
Distributable income..................................................................... $ 4,540
=======
Distributable income per Unit (12,000 Trust Units issued and outstanding)................ $ 0.38
=======
</TABLE>
See accompanying notes to unaudited pro forma financial statements.
F-12
<PAGE> 70
OCEAN ENERGY ROYALTY TRUST
UNAUDITED PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME
FOR THE YEAR ENDED DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
UNDERLYING
PROPERTIES OTHER COSTS CASH BASIS PRO FORMA
---------- ----------- ---------- ---------
(A) (B)
<S> <C> <C> <C> <C>
Revenues.......................................... $54,048 $9,167 $63,215
Direct Operating Expenses:
Production and property taxes................... 2,793 (12) 2,781
Production expenses............................. 5,785 (106) 5,679
------- -------
Total........................................... 8,578 8,460
------- -------
Excess of revenues over direct operating
expenses........................................ $45,470 54,755
=======
Development costs................................. $15,183 15,183
Overhead.......................................... 2,831 2,831
-------
Net proceeds............................................................................. 36,741
Net profits percentage................................................................... 45%
-------
Trust royalty income..................................................................... 16,533
Administrative expense................................................................... 500
-------
Distributable income..................................................................... $16,033
=======
Distributable income per Unit (12,000 Trust Units issued and outstanding)................ $ 1.34
=======
</TABLE>
See accompanying notes to unaudited pro forma financial statements.
F-13
<PAGE> 71
OCEAN ENERGY ROYALTY TRUST
UNAUDITED PRO FORMA STATEMENT OF ASSETS AND TRUST CORPUS
AS OF MARCH 31, 1999
(AMOUNTS IN THOUSANDS)
<TABLE>
<S> <C>
Cash........................................................ $
Net profits interests in oil and gas properties(c)..........
--------
Total Assets.............................................. $
========
Trust Corpus (12,000 units of beneficial interest authorized
and outstanding)(c)....................................... $
========
</TABLE>
See accompanying notes to unaudited pro forma financial statements.
F-14
<PAGE> 72
OCEAN ENERGY ROYALTY TRUST
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
(a) Deduct historical development costs and a Company overhead charge. The
overhead charge is based on a monthly count of active wells operated by
the Company.
(b) Adjustment from the accrual basis to the cash basis of accounting.
(c) Record net profits interest received of $ million (after
expenses of $ million) and the issuance of 12 million trust
units.
PRO FORMA SUPPLEMENTAL GAS RESERVE INFORMATION (UNAUDITED)
The reserve volumes presented are estimates only and should not be
construed as being exact quantities. These reserves may or may not be recovered
and may increase or decrease as a result of future operations and changes in
economic conditions.
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 natural gas reserves
or production quantities. Accordingly, reserves and production allocated to the
Trust pertaining to its 45% net profits interest in the working interest
properties have effectively been reduced to reflect recovery of the Trust's 45%
portion 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.
PROVED DEVELOPED RESERVES
<TABLE>
<CAPTION>
NATURAL GAS
(MMCF)
-----------
<S> <C>
Proved Reserves at July 1, 1999............................. 113,037
Proved Developed Reserves at July 1, 1999................... 96,749
</TABLE>
- - ---------------
The Trust's standardized measure of discounted future net cash flows as of
July 1, 1999 is presented based on the present value of future net revenues from
proved oil and gas reserves estimated by independent petroleum engineers in
accordance with guidelines established by the Securities and Exchange
Commission. These estimates are computed by applying appropriate period-end
prices for natural gas to estimated future production of proved natural gas
reserves over the economic lives of the reserves and assuming continuation of
existing operating conditions. The calculations below were made using a price of
$1.68 per thousand cubic feet of gas. The Net Profits Interests' 45% share of
production and development costs are netted in royalty income received by 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.
Because the disclosure requirements are standardized, significant changes
can occur in these estimates based upon gas prices in effect at the end of the
period. The following estimates should not be viewed as an estimate of fair
market value.
F-15
<PAGE> 73
OCEAN ENERGY ROYALTY TRUST
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
JULY 1, 1999
------------
<S> <C>
Future cash inflows......................................... $192,071
Future production taxes..................................... 10,245
--------
Future net cash flows....................................... 181,826
10% annual discount......................................... 80,136
--------
Standardized measure of discounted future net cash flows.... $101,690
========
</TABLE>
F-16
<PAGE> 74
UNDERWRITING
Ocean, the trust and the underwriters for the offering named below have
entered into an underwriting agreement with respect to the trust units being
offered. Subject to certain conditions, each underwriter has severally agreed to
purchase the number of trust units indicated in the following table. Goldman,
Sachs & Co. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are
representatives of the underwriters.
<TABLE>
<CAPTION>
Number of
Underwriter Trust Units
----------- -----------
<S> <C>
Goldman, Sachs & Co. .......................................
Merrill Lynch, Pierce, Fenner & Smith
Incorporated....................................
---------
Total............................................. 9,000,000
=========
</TABLE>
If the underwriters sell more trust units than the total number set forth
in the table above, the underwriters have an option to buy up to an additional
1,350,000 trust units from Ocean to cover such sales. They may exercise that
option for 30 days. If any trust units are purchased pursuant to this option,
the underwriters will severally purchase trust units in approximately the same
proportion as set forth in the table above.
The following table shows the per trust unit and total underwriting
discounts and commissions to be paid to the underwriters by Ocean. Such amounts
are shown assuming both no exercise and full exercise of the underwriters'
option to purchase additional trust units.
<TABLE>
<CAPTION>
Paid by Ocean
---------------------------
No Exercise Full Exercise
----------- -------------
<S> <C> <C>
Per trust unit.............................................. $ $
Total....................................................... $ $
</TABLE>
Trust units sold by the underwriters to the public will initially be
offered at the initial public offering price shown on the cover of this
prospectus. Any trust units sold by the underwriters to securities dealers may
be sold at a discount of up to $ per trust unit from the initial public
offering price. Any such securities dealers may resell any trust units purchased
from the underwriters to certain other brokers or dealers at a discount of up to
$ per trust unit from the initial public offering price. If all the trust
units are not sold at the initial offering price, the representatives may change
the offering price and the other selling terms.
Ocean and its executive officers have agreed with the underwriters not to
dispose of or hedge any of their trust units or securities convertible into or
exchangeable for trust units during the period from the date of this prospectus
continuing through the date 180 days after the date of this prospectus, except
with the prior written consent of the representatives. This agreement does not
apply to employee benefit plans or options.
Prior to the offering, there has been no public market for the trust units.
The initial public offering price has been negotiated among Ocean and the
representatives. Among the factors to be considered in determining the initial
public offering price of the trust units, in addition to prevailing market
conditions, will be estimates of distributions to trust unitholders and overall
quality of the underlying properties.
Ocean has applied to have the trust units approved for listing on the New
York Stock Exchange under the symbol " ." In order to meet one of the
requirements for listing the trust units on the New York Stock Exchange, the
underwriters have undertaken to sell lots of 100
U-1
<PAGE> 75
or more trust units to a minimum of 400 beneficial holders to establish at least
1,000,000 trust units in the public float having a minimum total public market
value of $4,000,000.
In connection with the offering, the underwriters may purchase and sell
trust units in the open market. These transactions may include short sales,
stabilizing transactions and purchases to cover positions created by short
sales. Short sales involve the sale by the underwriters of a greater number of
trust units than they are required to purchase in the offering. Stabilizing
transactions consist of certain bids or purchases made for the purpose of
preventing or retarding a decline in the market price of the trust units while
the offering is in progress.
The underwriters also may impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount received by it because the representatives have repurchased trust units
sold by or for the account of such underwriter in stabilizing or short covering
transactions.
These activities by the underwriters may stabilize, maintain or otherwise
affect the market price of the trust units. As a result, the price of the trust
units may be higher than the price that otherwise might exist in the open
market. If these activities are commenced, they may be discontinued by the
underwriters at any time. These transactions may be effected on the New York
Stock Exchange, in the over-the-counter market or otherwise.
The underwriters do not expect sales to discretionary accounts to exceed
five percent of the total number of trust units offered.
Ocean estimates that total expenses of the offering, excluding underwriting
discounts and commissions, will be approximately $ .
Ocean and the trust have agreed to indemnify the several underwriters
against certain liabilities, including liabilities under the Securities Act of
1933. 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.
U-2
<PAGE> 76
EXHIBIT A
[LOGO] [MILLER AND LENTS LETTERHEAD]
July 12, 1999
Ocean Energy, Inc.
1001 Fannin, Suite 1600
Houston, Texas 77002-6794
Re: Underlying Properties (100%)
Relating to the Ocean Energy Royalty Trust
As of July 1, 1999
SEC Pricing Case
Gentlemen:
At your request, we estimated the proved reserves and future net revenue as
of July 1, 1999 attributable to the Ocean Energy, Inc. (Ocean) interests in
certain oil and gas properties prior to inclusion in the Ocean Energy Royalty
Trust, i.e., Underlying Properties (100%). The properties are located in the
Arkoma Basin area of Arkansas and Oklahoma and in the Bear Paw area of north
central Montana. The aggregate results of our evaluations, using provisions
contained in Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10,
are as follows:
<TABLE>
<CAPTION>
ESTIMATES AS OF JULY 1, 1999
------------------------------------------------
NET RESERVES FUTURE NET REVENUE
------------- --------------------------------
GAS, UNDISCOUNTED, DISCOUNTED AT
RESERVES CATEGORY MMCF M$ 10% PER YEAR, M$
- - ----------------- ------------- ------------- ----------------
<S> <C> <C> <C>
ARKANSAS
Proved Developed Producing................. 160,314.0 249,666.8 142,407.2
Proved Developed Nonproducing.............. 2,074.3 3,375.0 1,252.4
Proved Undeveloped......................... 16,167.5 21,133.0 10,367.9
--------- --------- ---------
SUBTOTAL........................... 178,555.9 274,174.8 154,027.5
========= ========= =========
OKLAHOMA
Proved Developed Producing................. 19,643.6 28,139.5 16,059.8
Proved Developed Nonproducing.............. 605.3 909.8 334.5
Proved Undeveloped......................... 3,063.8 2,131.8 474.4
--------- --------- ---------
SUBTOTAL........................... 23,312.7 31,181.1 16,868.7
========= ========= =========
</TABLE>
<PAGE> 77
MILLER AND LENTS, LTD.
Ocean Energy, Inc. July 12, 1999
Page 2
<TABLE>
<CAPTION>
ESTIMATES AS OF JULY 1, 1999
------------------------------------------------
NET RESERVES FUTURE NET REVENUE
------------- --------------------------------
GAS, UNDISCOUNTED, DISCOUNTED AT
RESERVES CATEGORY MMCF M$ 10% PER YEAR, M$
- - ----------------- ------------- ------------- ----------------
<S> <C> <C> <C>
MONTANA
Proved Developed Producing................. 91,730.6 74,336.4 44,207.5
Proved Developed Nonproducing.............. 0.0 0.0 0.0
Proved Undeveloped......................... 45,570.5 23,974.0 10,627.7
--------- --------- ---------
SUBTOTAL........................... 137,301.2 98,310.4 54,835.2
========= ========= =========
TOTAL UNDERLYING PROPERTIES (100%)
Proved Developed Producing................. 271,688.3 352,142.7 202,674.5
Proved Developed Nonproducing.............. 2,679.6 4,284.8 1,586.8
Proved Undeveloped......................... 64,801.8 47,238.8 21,470.1
--------- --------- ---------
TOTAL.............................. 339,169.7 403,666.3 225,731.4
========= ========= =========
</TABLE>
The SEC definition of proved reserves is shown on the Appendix. Proved
developed reserves are subcategorized herein as producing and nonproducing.
Nonproducing reserves are attributable to wells requiring recompletion to
behind-pipe zones or awaiting sales connection. The evaluated properties produce
dry gas. Oil, condensate, and natural gas liquids production is insignificant
and has not been considered herein. Natural gas volumes are stated at the
pressure and temperature bases of the appropriate state regulatory body or gas
sales contract.
Estimates of future net revenue and discounted future net revenue are not
intended and should not be interpreted to represent fair market values for the
estimated reserves. Future costs of abandoning facilities and wells and any
future costs of restoration of producing properties to satisfy environmental
standards were not deducted from total revenues as such estimates are beyond the
scope of this assignment.
Annual projections of future production and net revenue for each state and
reserve category are included as exhibits to this report. Also included in the
exhibits are one-line summaries for each state showing the proved reserves and
future net revenue for the individual properties. Each of these exhibits is
identified in the List of Exhibits. These exhibits should not be relied upon
independently of this narrative.
The proved reserves were estimated from extrapolations of performance
trends, material balance calculations, volumetric calculations, analogies, or a
combination of these methods. Reserve estimates from volumetric calculations and
from analogies are often less certain than reserve estimates based on well
performance obtained over a period during which a substantial portion of the
reserves was produced. Future production forecasts were projected based on
historical trends, deliverability calculations, or analogies and were limited by
allowable or facility restrictions. No provisions for gas sales imbalances were
included in our projections and estimates.
Ocean provided the product prices, gathering system fees, operating
expenses, and capital costs used in our projections and represented to Miller
and Lents, Ltd. that they are in compliance with SEC regulations for estimates
of reserves and future revenues. Gathering system charges were handled in our
projections as an adjustment to revenue. No future escalations were applied
either to prices or to unit costs and expenses. Additional costs for
<PAGE> 78
MILLER AND LENTS, LTD.
Ocean Energy, Inc. July 12, 1999
Page 3
installation and operation of rental compression were included for wells that
were expected to benefit from such installations. Scheduling for development
drilling and compression installation were provided by Ocean. Recompletions were
scheduled based on our estimates of wellbore availability, usually at the time
of depletion for the previously produced zone. No overhead charges were included
for those properties operated by Ocean.
In conducting this evaluation, we relied upon production histories, test
data, accounting and cost data, and other engineering and geologic data supplied
by Ocean. To a lesser extent, we used information from public records and
nonconfidential data from the files of Miller and Lents, Ltd. We accepted
representations by Ocean regarding ownership interests without independent
verification, as such is not within the scope of this report.
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those employed in this study may cause the total
quantity of oil or gas to be recovered, actual production rates, prices
received, or operating and capital costs to vary from those presented in this
report.
Miller and Lents, Ltd. is an independent oil and gas consulting firm.
Neither our engagement for this investigation nor our compensation was
contingent on the results of our study. None of the officers of this firm hold a
financial interest in Ocean or its subsidiaries and we have performed no other
work that would affect our objectivity. Production of this report was supervised
by an officer of the company who is a professionally qualified and Registered
Professional Engineer in the State of Texas with more than five years of
relevant professional experience in the estimation, assessment, and evaluation
of oil and gas reserves.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ GREGORY W. ARMES
-----------------------------------
Gregory W. Armes
Senior Vice President
RWF/hsd
Enclosures
<PAGE> 79
APPENDIX
PROVED RESERVES DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
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 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 contracts, 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. I the absence of information on fluid
contracts, the lowed 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 reservoirs provided 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.
d. Crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite, and other such sources.
Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.
PROVED DEVELOPED OIL AND GAS RESERVES
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.
<PAGE> 80
PROVED UNDEVELOPED OIL AND GAS RESERVES
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. under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual test in the area and in the same
reservoir.
<PAGE> 81
EXHIBIT B
[LOGO] [MILLER AND LENTS LETTERHEAD]
July 12, 1999
Ocean Energy, Inc.
1001 Fannin, Suite 1600
Houston, Texas 77002-6794
Re: Ocean Energy Royalty Trust
45% Net Profits Interests
As of July 1, 1999
SEC Pricing Case
Gentlemen:
At your request, we estimated the proved reserves and future net revenue as
of July 1, 1999 attributable to the Ocean Energy Royalty Trust (the Trust)
interests in certain oil and gas properties after the Trust is established by
Ocean Energy, Inc. (Ocean). The properties are located in the Arkoma Basin area
of Arkansas and Oklahoma and in the Bear Paw area of north central Montana. The
aggregate results of our evaluations, using provisions contained in Securities
and Exchange Commission (SEC) Regulation S-X, Rule 4-10, are as follows:
<TABLE>
<CAPTION>
ESTIMATES AS OF JULY 1, 1999
------------------------------------------------
NET RESERVES FUTURE NET REVENUE
------------- --------------------------------
GAS, UNDISCOUNTED, DISCOUNTED AT
RESERVES CATEGORY MMCF M$ 10% PER YEAR, M$
- - ----------------- ------------- ------------- ----------------
<S> <C> <C> <C>
ARKANSAS
Proved Developed Producing................. 54,948.0 112,470.8 64,161.9
Proved Developed Nonproducing.............. 740.1 1,518.8 563.6
Proved Undeveloped......................... 4,568.1 9,509.8 4,665.6
--------- --------- ---------
SUBTOTAL........................... 60,256.3 123,499.3 69,391.0
========= ========= =========
OKLAHOMA
Proved Developed Producing................. 6,750.2 12,662.5 7,226.7
Proved Developed Nonproducing.............. 200.7 409.4 150.5
Proved Undeveloped......................... 507.1 959.3 213.5
--------- --------- ---------
SUBTOTAL........................... 7,457.9 14,031.2 7,590.7
========= ========= =========
</TABLE>
<PAGE> 82
MILLER AND LENTS, LTD.
Ocean Energy, Inc. July 12, 1999
Page 2
<TABLE>
<CAPTION>
ESTIMATES AS OF JULY 1, 1999
------------------------------------------------
NET RESERVES FUTURE NET REVENUE
------------- --------------------------------
GAS, UNDISCOUNTED, DISCOUNTED AT
RESERVES CATEGORY MMCF M$ 10% PER YEAR, M$
- - ----------------- ------------- ------------- ----------------
<S> <C> <C> <C>
MONTANA
Proved Developed Producing................. 34,110.2 33,457.7 19,896.6
Proved Developed Nonproducing.............. 0.0 0.0 0.0
Proved Undeveloped......................... 11,212.8 10,837.4 4,811.6
--------- --------- ---------
SUBTOTAL........................... 45,323.0 44,295.1 24,708.3
========= ========= =========
TOTAL OCEAN ENERGY ROYALTY TRUST
Proved Developed Producing................. 95,808.4 158,591.0 91,285.2
Proved Developed Nonproducing.............. 940.7 1,928.2 714.1
Proved Undeveloped......................... 16,288.1 21,306.5 9,690.7
--------- --------- ---------
TOTAL.............................. 113,037.2 181,825.6 101,690.0
========= ========= =========
</TABLE>
The SEC definition of proved reserves is shown on the Appendix. Proved
developed reserves are subcategorized herein as producing and nonproducing.
Nonproducing reserves are attributable to wells requiring recompletion to
behind-pipe zones or awaiting sales connection. The evaluated properties produce
dry gas. Oil, condensate, and natural gas liquids production is insignificant
and has not been considered herein. Natural gas volumes are stated at the
pressure and temperature bases of the appropriate state regulatory body or gas
sales contract.
Estimates of future net revenue and discounted future net revenue are not
intended and should not be interpreted to represent fair market values for the
estimated reserves. Future costs of abandoning facilities and wells and any
future costs of restoration of producing properties to satisfy environmental
standards were not deducted from total revenues as such estimates are beyond the
scope of this assignment.
The Trust interests evaluated herein are comprised of a 45 percent net
profits interest from certain Ocean properties. At your instruction, the net gas
reserves attributable to the Trust interests were computed from 45 percent of
Ocean's interests in those properties after adjustment for the estimated
reserves attributable to the future operating expenses and capital costs. As a
result of this procedure, a change in the future costs, or prices, or capital
expenditures different from those projected herein may result in a change in the
computed reserves to the net interests even if there are no revisions or
additions to the gross reserves attributed to the property.
Annual projections of future production and net revenue for each state and
reserve category are included as exhibits to this report. Also included in the
exhibits are one-line summaries for each state showing the proved reserves and
future net revenue for the individual properties. Each of these exhibits is
identified in the List of Exhibits. These exhibits should not be relied upon
independently of this narrative.
The proved reserves were estimated from extrapolations of performance
trends, material balance calculations, volumetric calculations, analogies, or a
combination of these methods. Reserve estimates from volumetric calculations and
from analogies are often less certain than reserve estimates based on well
performance obtained over a period during which a substantial portion of the
reserves was produced. Future production forecasts were projected based on
<PAGE> 83
MILLER AND LENTS, LTD.
Ocean Energy, Inc. July 12, 1999
Page 3
historical trends, deliverability calculations, or analogies and were limited by
allowable or facility restrictions. No provisions for gas sales imbalances were
included in our projections and estimates.
Ocean provided the product prices, gathering system fees, operating
expenses, and capital costs used in our projections and represented to Miller
and Lents, Ltd. that they are in compliance with SEC regulations for estimates
of reserves and future revenues. Gathering system charges were handled in our
projections as an adjustment to revenue. No future escalations were applied
either to prices or to unit costs and expenses. Additional costs for
installation and operation of rental compression were included for wells that
were expected to benefit from such installations. Scheduling for development
drilling and compression installation were provided by Ocean. Recompletions were
scheduled based on our estimates of wellbore availability, usually at the time
of depletion for the previously produced zone. No overhead charges were included
for those properties operated by Ocean.
In conducting this evaluation, we relied upon production histories, test
data, accounting and cost data, and other engineering and geologic data supplied
by Ocean. To a lesser extent, we used information from public records and
nonconfidential data from the files of Miller and Lents, Ltd. We accepted
representations by Ocean regarding ownership interests without independent
verification, as such is not within the scope of this report.
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those employed in this study may cause the total
quantity of oil or gas to be recovered, actual production rates, prices
received, or operating and capital costs to vary from those presented in this
report.
Miller and Lents, Ltd. is an independent oil and gas consulting firm.
Neither our engagement for this investigation nor our compensation was
contingent on the results of our study. None of the officers of this firm hold a
financial interest in Ocean or its subsidiaries and we have performed no other
work that would affect our objectivity. Production of this report was supervised
by an officer of the company who is a professionally qualified and Registered
Professional Engineer in the State of Texas with more than five years of
relevant professional experience in the estimation, assessment, and evaluation
of oil and gas reserves.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ GREGORY W. ARMES
-----------------------------------
Gregory W. Armes
Senior Vice President
RWF/hsd
Enclosures
<PAGE> 84
APPENDIX
PROVED RESERVES DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
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 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 contracts, 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. I the absence of information on fluid
contracts, the lowed 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 reservoirs provided 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.
d. Crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite, and other such sources.
Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.
PROVED DEVELOPED OIL AND GAS RESERVES
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.
<PAGE> 85
PROVED UNDEVELOPED OIL AND GAS RESERVES
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. under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual test in the area and in the same
reservoir.
<PAGE> 86
- - ------------------------------------------------------
- - ------------------------------------------------------
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
only 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.
----------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Prospectus Summary.................... 1
Risk Factors.......................... 9
Forward Looking Statements............ 14
Use of Proceeds....................... 14
Ocean Energy, Inc. ................... 15
The Trust............................. 15
Projected Cash Distributions.......... 15
The Underlying Properties............. 19
Computation of Net Proceeds........... 30
Federal Income Tax Consequences....... 33
State Tax Considerations.............. 41
ERISA Considerations.................. 43
Description of the Trust Agreement.... 43
Description of the Trust Units........ 47
Legal Matters......................... 49
Experts............................... 49
Where You Can Find More
Information......................... 50
Glossary of Certain Oil and Natural
Gas Terms........................... 52
Index to Financial Statements......... F-1
Underwriting.......................... U-1
Summary Reserve Reports.....Exhibits A and B
</TABLE>
----------------------
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.
- - ------------------------------------------------------
- - ------------------------------------------------------
- - ------------------------------------------------------
- - ------------------------------------------------------
9,000,000 Trust Units
OCEAN ENERGY
ROYALTY TRUST
----------------------
PROSPECTUS
----------------------
GOLDMAN, SACHS & CO.
MERRILL LYNCH & CO.
Representatives of the Underwriters
- - ------------------------------------------------------
- - ------------------------------------------------------
<PAGE> 87
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13 -- OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The following table sets forth the estimated expenses in connection with
the distribution of the securities covered by this Registration Statement. All
of the expenses will be borne by Ocean except as otherwise indicated.
<TABLE>
<S> <C>
Registration fee............................................ $27,800
NASD Filing Fee.............................................
Fees and expenses of accountants............................
Fees and expenses of legal counsel..........................
Printing and engraving expenses.............................
Miscellaneous...............................................
-------
Total............................................. $
=======
</TABLE>
ITEM 14 -- INDEMNIFICATION OF DIRECTORS AND OFFICERS
The trust agreement provides that the property trustee and its officers,
agents and employees shall be indemnified from the assets of the trust against
and from any and all liabilities, expenses, claims, damages or loss incurred by
it individually or as property trustee in the administration of the trust and
the trust assets, including, without limitation, any liability, expenses,
claims, damages or loss arising out of or in connection with any liability under
environmental laws, or in the doing of any act done or performed or omission
occurring on account of it being trustee or acting in such capacity, except such
liability, expense, claims, damages or loss as to which it is liable under the
trust agreement. In this regard, the property trustee shall be liable only for
fraud or gross negligence or for acts or omissions in bad faith and shall not be
liable for any act or omission of any agent or employee unless the trustee has
acted in bad faith or with gross negligence in the selection and retention of
such agent or employee. The property trustee is entitled to indemnification from
the assets of the trust and shall have a lien on the assets of the trust to
secure it for the foregoing indemnification.
Article 2.02-1 of the Texas Business Corporation Act provides that any
director or officer of a Texas corporation may be indemnified against judgments,
penalties (including excise and similar taxes), fines, settlements and
reasonable expenses actually incurred by him in connection with or in defending
any threatened, pending, or completed action, suit or proceeding, whether civil,
criminal, administrative, arbitrative or investigative, any appeal in such an
action suit or proceeding, and any inquiry or investigation that could lead to
such an action, suit or proceeding, in which he is a party or to which he is
subject by reason of his position. With respect to any proceeding arising from
actions taken in his official capacity, as a director or officer, he may be
indemnified so long as it shall be determined that he conducted himself in good
faith and that he reasonably believed that such conduct was in the corporation's
best interest. In cases not concerning conduct in his official capacity as a
director or officer, a director or officer may be indemnified so long as it
shall be determined that he conducted himself in good faith and that he
reasonably believed that his conduct was not opposed to the corporation's best
interest. In the case of any criminal proceeding, a director or officer may be
indemnified if he had no reasonable cause to believe his conduct was unlawful.
If a director or officer is wholly successful, on the merits or otherwise, in
connection with such a proceeding, such indemnification is mandatory. Article VI
of Ocean's Bylaws requires the indemnification of officers and directors to the
fullest extent permitted by the Texas Business Corporation Act.
II-1
<PAGE> 88
Ocean maintains insurance coverage providing its officers and directors
with indemnification against certain liabilities for actions taken in such
capacities, including liabilities under the Securities Act of 1933.
Reference is made to Article Eleven of the Articles of Incorporation of
Ocean, which was adopted by Ocean's shareholders on May 11, 1988 and which
provides as follows: "ARTICLE ELEVEN. A director of the corporation shall not be
liable to the corporation or its shareholders for monetary damages for an act or
omission in the director's capacity as a director, except for liability (i) for
any breach of the director's duty of loyalty to the corporation or its
shareholders; (ii) for acts or omissions not in good faith or that involve
intentional misconduct or a knowing violation of law; (iii) for any transaction
from which the director received an improper benefit, whether or not the benefit
resulted from an action taken within the scope of the director's office; (iv)
for acts or omissions for which the liability of a director is expressly
provided for by statute; or (v) for acts related to an unlawful stock repurchase
or dividend payment. Any repeal or amendment of this Article by the shareholders
of the corporation shall be prospective only, and shall not adversely affect any
limitation on the liability of a director of the corporation existing at the
time of such repeal or amendment. In addition to the circumstances in which a
director of the corporation is not liable as set forth in the preceding
sentences, a director shall not be liable to the fullest extent permitted by any
provision of the statutes of Texas hereafter enacted that further limits the
liability of a director."
Effective as of August 28, 1989, Article 7.06.B of the Texas Miscellaneous
Corporation Laws Act was amended to read in its entirety as follows: "B. The
articles of incorporation of a corporation may provide that a director of the
corporation shall not be liable, or shall be liable only to the extent provided
in the articles of incorporation, to the corporation or its shareholders or
members for monetary damages for an act or omission in the director's capacity
as a director, except that this article does not authorize the elimination or
limitation of the liability of a director to the extent the director is found
liable for: (1) a breach of the director's duty of loyalty to the corporation or
its shareholders or members; (2) an act or omission not in good faith that
constitutes a breach of duty of the director to the corporation or an act or
omission that involves intentional misconduct or a knowing violation of the law;
(3) a transaction from which the director received an improper benefit, whether
or not the benefit resulted from an action taken within the scope of the
director's office; or (4) an act or omission for which the liability of a
director is expressly provided for by an applicable statute."
The Agreement and Plan of Merger between Ocean and Ocean Energy, Inc., a
Delaware corporation ("OEI"), dated November 24, 1998, as amended (the "Merger
Agreement") provides that Ocean will, for six years after the effective time of
the merger contemplated thereby indemnify, defend and hold harmless each person
who is, has been or becomes prior to the effective time of the merger an officer
or director of OEI and its subsidiaries or an employee of OEI or any of its
subsidiaries who acts as fiduciary under any OEI benefit plan against all
losses, claims, damages, liabilities, fees and expenses arising in whole or in
part out of actions or omissions in their capacity as such that occur prior to
the effective time. Such indemnification is made to the full extent permitted
under Texas law or Ocean's Articles of Incorporation and Bylaws and OEI's
written indemnification agreements in effect as of November 24, 1998. Any
determination of whether a person's conduct complies with the required standard
will be made by independent counsel acceptable to both Ocean and the indemnified
party.
Ocean will also maintain OEI's existing directors' and officers' liability
insurance policy (or a policy with substantially similar coverage) for not less
than six years after the effective time of the merger but only to the extent
related to actions or omissions prior to the effective time of the merger,
provided that the aggregate premium for maintaining such policy for the six year
period will not exceed $2,500,000.00. Additionally, Ocean will maintain the
directors' and officers' insurance policy of United Meridian Corporation as
currently in effect until March 27, 2003.
II-2
<PAGE> 89
ITEM 15 -- RECENT SALES OF UNREGISTERED SECURITIES
None.
ITEM 16 -- EXHIBITS
There are filed with this Registration Statement the following exhibits:
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
**1.1 -- Form of Underwriting Agreement.
4.1 -- Articles of Incorporation of Ocean, as amended, including
Articles of Amendment filed May 12, 1988, May 21, 1999,
and May 21, 1993 with the Secretary of State of the State
of Texas, Articles of Merger filed March 30, 1999 with
the Secretary of State of the State of Texas (filed as
Exhibit 4.1 to Ocean's Registration Statement on Form S-8
filed with the Commission on May 11, 1999 and
incorporated herein by reference) and that certain
Statement of Resolution Establishing Series of Shares of
Series B Junior Participating Preferred Stock of Ocean
filed March 21, 1989 with the Secretary of State of the
State of Texas (filed as Exhibit 3.1 to Ocean's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1998
and incorporated herein by reference).
4.2 -- Bylaws of Ocean, as amended through March 7, 1997 (filed
as Exhibit 4.9 to Ocean's Registration Statement on Form
S-3 filed with the Securities and Exchange Commission on
September 18, 1997 and incorporated herein by reference).
4.3 -- Amended and Restated Rights Agreement, dated March 17,
1989, as amended effective June 13, 1992 and amended and
restated as of December 12, 1997, between Ocean and
BankBoston, N.A. (as successor to NCNB Texas National
Bank), including Form of Statement of Resolution
Establishing the Series B Junior Participating Preferred
Stock, the Form of Right Certificate and Form of Summary
of Rights to Purchase Preferred Shares (filed as Exhibit
2 to Ocean's Current Report on Form 8-K dated December
15, 1997 and incorporated herein by reference).
4.4 -- Amendment No. 1 to Amended and Restated Rights Agreement
dated November 24, 1998, between Ocean and BankBoston,
N.A. (filed as Exhibit 4.1 to Ocean's Current Report on
Form 8-K filed with the Securities and Exchange
Commission on December 1, 1998 and incorporated herein by
reference).
4.5 -- Amendment No. 2 to Amended and Restated Rights Agreement
dated March 10, 1999, between Ocean and BankBoston, N.A.
(filed as Exhibit 4.1 to Ocean's Current Report on Form
8-K filed with the Securities and Exchange Commission on
March 12, 1999 and incorporated herein by reference).
4.6 -- Amendment No. 3 to Amended and Restated Rights Agreement
dated May 21, 1999, between Ocean and BankBoston, N.A.
(filed as Exhibit 4.1 to Ocean's Current Report on Form
8-K filed with the Securities and Exchange Commission on
May 21, 1999 and incorporated herein by reference).
</TABLE>
II-3
<PAGE> 90
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
4.7 -- Revolving Credit Agreement, dated as of March 30, 1999,
among Ocean, Chase Bank of Texas, National Association
("Chase Texas") (Individually and as Administrative
Agent), The Chase Manhattan Bank ("Chase Manhattan") (as
Auction Administrative Agent), Bank of America National
Trust and Savings Association ("Bank of America")
(Individually and as Syndication Agent), Bank One Texas,
N. A. ("Bank One") (Individually and as Documentation
Agent), Societe Generale, Southwest Agency ("Societe
Generale") (Individually and as Managing Agent), the Bank
of Montreal (Individually and as Managing Agent), and the
other Banks signatory thereto.
4.8 -- 364-day Credit Agreement, dated as of March 30, 1999,
among Ocean, Chase Texas (Individually and as
Administrative Agent), Chase Manhattan (as Auction
Administrative Agent), Bank of America (Individually and
as Syndication Agent), Bank One (Individually and as
Documentation Agent), Societe Generale (Individually and
as Managing Agent), the Bank of Montreal (Individually
and as Managing Agent), and the other Banks signatory
thereto.
*4.9 -- Ocean Energy Royalty Trust -- Trust Agreement.
**4.10 -- Ocean Energy Royalty Trust -- Amended and Restated Trust
Agreement.
*4.11 -- Ocean Energy Royalty Trust -- Certificate of Trust.
4.12 -- Indenture, dated as of July 8, 1998, among Ocean Energy,
Inc., its Subsidiary Guarantors, and U.S. Bank Trust
National Association, relating to the 8 3/8% Series A
Senior Subordinated Notes due 2008 and the 8 3/8% Series
B Senior Subordinated Notes due 2008, as amended by First
Supplemental Indenture dated March 30, 1999, incorporated
by reference to Exhibit 10.22 to the Form 10-Q for the
period ended June 30, 1998 of Ocean Energy, Inc.
(Registration No. 0-25058) filed with the Securities and
Exchange Commission on August 14, 1998 and, with respect
to the First Supplemental Indenture, to Exhibit 4.3 to
the Registrant's Form 10-Q for the period ended March 31,
1999.
4.13 -- Indenture, dated as of July 8, 1998, among Ocean Energy,
Inc., its Subsidiary Guarantors, and Norwest Bank
Minnesota, National Association (Norwest Bank) as
Property trustee, relating to the 7 5/8% Senior Notes due
2005, as amended by First Supplemental Indenture dated
March 30, 1999, incorporated by reference to Exhibit
10.23 to the Form 10-Q for the period ended June 30, 1998
of Ocean Energy, Inc. (Registration No. 0-25058) filed
with the Securities and Exchange Commission on August 14,
1998 and, with respect to the First Supplemental
Indenture, to Exhibit 4.4 to the Registrant's Form 10-Q
for the period ended March 31, 1999.
4.14 -- Indenture, dated as of July 8, 1998, among Ocean Energy,
Inc., its Subsidiary Guarantors, and Norwest Bank as
Property trustee, relating to the 8 1/4% Senior Notes due
2018, as amended by First Supplemental Indenture dated
March 30, 1999, incorporated by reference to Exhibit
10.24 to the Form 10-Q for the period ended June 30, 1998
of Ocean Energy, Inc. (Registration No. 0-25058) filed
with the Securities and Exchange Commission on August 14,
1998 and, with respect to the First Supplemental
Indenture, to Exhibit 4.5 to the Registrant's Form 10-Q
for the period ended March 31, 1999.
</TABLE>
II-4
<PAGE> 91
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
4.15 -- Indenture, dated as of July 2, 1997, among Ocean Energy,
Inc., the Subsidiary Guarantors Named Therein and State
Street Bank and Trust Company, as Property trustee,
relating to the 8 7/8% Senior Subordinated Notes due 2007
(the Indenture is incorporated by reference to Exhibit
4.1 to the Registration Statement on Form S-4 (No.
333-32715) of Ocean Energy, Inc. filed with the SEC on
August 1, 1997; the First Supplemental Indenture, dated
as of March 27, 1998, is incorporated by reference to
Exhibit 10.11 to the Form 8-K of Ocean Energy, Inc.
(Registration No. 0-25058) filed with the Securities and
Exchange Commission on March 31, 1998); and the Second
Supplemental Indenture dated March 30, 1999 is
incorporated by reference to Exhibit 4.6 to the
Registrant's Form 10-Q for the period ended March 31,
1999.
4.16 -- Indenture, dated as of September 26, 1996, among Ocean
Energy, Inc. (f/k/a Flores & Rucks, Inc.), the Subsidiary
Guarantors Named Therein and Fleet National Bank, as
Property trustee, relating to the 9 3/4% Senior
Subordinated Notes Due 2006 (the Indenture is
incorporated by reference to Exhibit 4.1 to the Quarterly
Report on Form 10-Q for the quarter ended September 30,
1996 of Ocean Energy, Inc. (Registration No. 0-25058);
the First Supplemental Indenture, dated as of March 27,
1998, is incorporated by reference to Exhibit 10.10 to
the Form 8-K of Ocean Energy, Inc. (Registration No.
0-25058) filed with the Securities and Exchange
Commission on March 31, 1998; and the Second Supplemental
Indenture dated March 30, 1999 is incorporated by
reference to Exhibit 4.7 to the Registrant's Form 10-Q
for the period ended March 31, 1999.
4.17 -- Indenture, dated as of October 30, 1995, among Ocean
Energy, Inc., a Delaware corporation (successor by merger
to United Meridian Corporation), Ocean Energy, Inc., a
Louisiana corporation (successor by merger to UMC
Petroleum Corporation) and Bank of Montreal Trust
Company, as Property trustee, relating to the 10 3/8%
Senior Subordinated Notes Due 2005 (the Indenture is
incorporated by reference to Exhibit 4.20 to UMC's Annual
Report on Form 10-K for the year ended December 31, 1995;
the First Supplemental Indenture, dated as of November 4,
1997, is incorporated by reference to Exhibit 4.11 to the
Form 10-Q for the quarter ended September 30, 1998 of
Ocean Energy, Inc. (Registration No. 0-25058); the Second
Supplemental Indenture, dated as of March 27, 1998, is
incorporated by reference to Exhibit 10.12 to the Form
8-K of Ocean Energy, Inc. (Registration No. 0-25058)
filed with the Securities and Exchange Commission on
March 31, 1998); and the Third Supplemental Indenture
dated March 30, 1999 is incorporated by reference to
Exhibit 4.8 to the Registrant's Form 10-Q for the period
ended March 31, 1999.
</TABLE>
II-5
<PAGE> 92
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
4.18 -- Indenture, dated as of December 1, 1994, among Ocean
Energy, Inc. (f/k/a Flores & Rucks, Inc.), the Subsidiary
Guarantors Named Therein and Chimed Bank Connecticut,
National Association, as Property trustee, relating to
the 13 1/2% Senior Notes Due 2004, (the Indenture is
incorporated by reference to Exhibit 4.1 to the Annual
Report on Form 10-K for the year ended December 31, 1994
of Ocean Energy, Inc. (Registration No. 0-25058); the
First Supplemental Indenture, dated as of September 19,
1996, is incorporated by reference to Exhibit 4.1 to the
Form 8-K of Ocean Energy, Inc. (Registration No. 0-25058)
filed with the Securities and Exchange Commission on
October 10, 1996; the Second Supplemental Indenture,
dated as of July 14, 1997, is incorporated by reference
to Exhibit 4.1 to the Quarterly Report on Form 10-Q for
the quarter ended September 30, 1997 of Ocean Energy,
Inc. (Registration No. 0-25058); the Third Supplemental
Indenture, dated as of March 27, 1998, is incorporated by
reference to Exhibit 10.9 to the Form 8-K of Ocean
Energy, Inc. (Registration No. 0-25058) filed with the
Securities and Exchange Commission on March 31, 1998);
and the Fourth Supplemental Indenture dated March 30,
1999 is incorporated by reference to Exhibit 4.9 to the
Registrant's Form 10-Q for the period ended March 31,
1999.
**5.1 -- Opinion of Richards, Layton & Finger, P.A. as to the
validity of the securities offered hereby.
**8.1 -- Opinion of Vinson & Elkins L.L.P. regarding federal
income tax matters.
**10.1 -- Form of Net Overriding Royalty Conveyance -- Arkansas.
**10.2 -- Form of Net Overriding Royalty Conveyance -- Montana.
**10.3 -- Form of Net Overriding Royalty Conveyance -- Oklahoma.
*23.1 -- Consent of KPMG LLP.
*23.2 -- Consent of Arthur Andersen LLP.
*23.3 -- Consent of Miller & Lents.
*23.4 -- Consent of DeGolyer and MacNaughton.
*23.5 -- Consent of Netherland, Sewell & Associates, Inc.
*23.6 -- Consent of Ryder Scott Company Petroleum Engineers.
*23.7 -- Consent of McDaniel & Associates Consultants Ltd.
*23.8 -- Consent of Netherland, Sewell & Associates, Inc. -- Ocean
Energy, Inc. (Delaware).
*23.9 -- Consent of Ryder Scott Company Petroleum
Engineers -- Ocean Energy, Inc. (Delaware).
**23.10 -- Consent of Richards, Layton & Finger, P.A. (included in
the opinion filed as Exhibit 5.1 of this Registration
Statement).
**23.11 -- Consent of Vinson & Elkins L.L.P. (included in the
opinion filed as Exhibit 8.1 of this Registration
Statement).
**24.1 -- Power of Attorney (included in the signature page of this
Registration Statement).
</TABLE>
- - ---------------
* Filed herewith.
** To be filed by amendment.
II-6
<PAGE> 93
ITEM 17 -- UNDERTAKINGS
The undersigned registrants hereby undertake:
(a) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(1) To include any prospectus required by Section 10(a)(3) of the
Securities Act of 1933;
(2) To reflect in the prospectus any facts or events arising after the
effective date of this registration statement (or the most recent
post-effective amendment thereof) which, individually or in the aggregate,
represent a fundamental change in the information set forth in this
registration statement; and
(3) To include any material information with respect to the plan of
distribution not previously disclosed in this registration statement or any
material change to such information in this registration statement;
provided, however, that clauses (1) and (2) above do not apply if the
information required to be included in a post-effective amendment by those
clauses is contained in periodic reports filed by the registrants pursuant to
Section 13 or Section 15(d) of the Securities Exchange Act of 1934 that are
incorporated by reference into this registration statement;
(b) That, for the purpose of determining any liability under the Securities
Act of 1933, each such post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of the securities at that time shall be deemed to be the initial bona
fide offering thereof; and
(c) To remove from registration by means of a post-effective amendment any
of the securities being registered that remain unsold at the termination of the
offering.
The undersigned registrants hereby undertake that, for purposes of
determining any liability under the Securities Act of 1933, each filing of
Ocean's annual report pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 that is incorporated by reference in this registration
statement shall be deemed to be a new registration statement relating to the
securities offered therein, and the offering of the 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 the
registrants pursuant to the provisions described in Item 14 above or otherwise,
the registrants have been advised that in the opinion of the SEC such
indemnification is against public policy as expressed in the Securities Act of
1933 and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrants of expenses incurred or paid by a director, officer, or controlling
person of the registrant in the successful defense of any action, suit, or
proceeding) is asserted by the director, officer, or controlling person in
connection with the securities being registered, the 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 the issue.
II-7
<PAGE> 94
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Registration Statement to be filed on its behalf by the
undersigned, thereunto duly authorized, in Houston, Texas on July 15, 1999.
OCEAN ENERGY ROYALTY TRUST
By: OCEAN ENERGY, INC., as sponsor
By: /s/ JAMES T. HACKETT
----------------------------------
James T. Hackett
President and Chief Executive
Officer
II-8
<PAGE> 95
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements for filing on Form S-3 and has duly caused this Registration
Statement on Form S-3 to be signed on its behalf by the undersigned, thereunto
duly authorized, in Houston, Texas, on July 15, 1999.
OCEAN ENERGY, INC.
By: /s/ JAMES T. HACKETT
----------------------------------
James T. Hackett
President and Chief Executive
Officer
II-9
<PAGE> 96
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement on Form S-3 has been signed by the following persons in
the capacities and on the dates indicated.
POWER OF ATTORNEY
Each person whose signature appears below appoints James T. Hackett,
William L. Transier and Robert K. Reeves, and any of them, any of whom may act
without the joinder of any other, as his true and lawful attorneys-in-fact and
agents, with full power of substitution and resubstitution, for him, and in his
name, place and stead, in any and all capacities to sign any and all amendments
(including post-effective amendments) to this registration statement, and to
file the same, with all exhibits thereto and all other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents full power and authority to do and perform each and
every act and thing requisite and necessary to be done, as fully to all intents
and purposes as he might or could do in person, hereby ratifying and confirming
all that said attorneys-in-fact and agents or their substitute or substitutes
may lawfully do or cause to be done by virtue hereof.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ JAMES C. FLORES Chairman of the Board and July 15, 1999
- - ----------------------------------------------------- Director
James C. Flores
/s/ JAMES T. HACKETT President and Chief Executive July 15, 1999
- - ----------------------------------------------------- Officer and Director
James T. Hackett (Principal Executive Officer)
/s/ WILLIAM L. TRANSIER Executive Vice President and July 15, 1999
- - ----------------------------------------------------- Chief Financial Officer
William L. Transier (Principal Financial Officer)
/s/ GORDON L. MCCONNELL Vice President and Controller July 15, 1999
- - ----------------------------------------------------- (Principal Accounting Officer)
Gordon L. McConnell
/s/ J. EVANS ATTWELL Director July 15, 1999
- - -----------------------------------------------------
J. Evans Attwell
/s/ JOHN B. BROCK Director July 15, 1999
- - -----------------------------------------------------
John B. Brock
/s/ MILTON CARROLL Director July 15, 1999
- - -----------------------------------------------------
Milton Carroll
/s/ THOMAS D. CLARK, JR. Director July 15, 1999
- - -----------------------------------------------------
Thomas D. Clark, Jr.
/s/ PETER J. FLUOR Director July 15, 1999
- - -----------------------------------------------------
Peter J. Fluor
/s/ BARRY J. GALT Director July 15, 1999
- - -----------------------------------------------------
Barry J. Galt
</TABLE>
II-10
<PAGE> 97
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ ROBERT L. HOWARD Director July 15, 1999
- - -----------------------------------------------------
Robert L. Howard
/s/ ELVIS L. MASON Director July 15, 1999
- - -----------------------------------------------------
Elvis L. Mason
/s/ CHARLES F. MITCHELL Director July 15, 1999
- - -----------------------------------------------------
Charles F. Mitchell
/s/ DAVID K. NEWBIGGING Director July 15, 1999
- - -----------------------------------------------------
David K. Newbigging
/s/ DEE S. OSBORNE Director July 15, 1999
- - -----------------------------------------------------
Dee S. Osborne
/s/ R. A. WALKER Director July 15, 1999
- - -----------------------------------------------------
R. A. Walker
</TABLE>
II-11
<PAGE> 98
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
**1.1 -- Form of Underwriting Agreement.
4.1 -- Articles of Incorporation of Ocean, as amended, including
Articles of Amendment filed May 12, 1988, May 21, 1999,
and May 21, 1993 with the Secretary of State of the State
of Texas, Articles of Merger filed March 30, 1999 with
the Secretary of State of the State of Texas (filed as
Exhibit 4.1 to Ocean's Registration Statement on Form S-8
filed with the Commission on May 11, 1999 and
incorporated herein by reference) and that certain
Statement of Resolution Establishing Series of Shares of
Series B Junior Participating Preferred Stock of Ocean
filed March 21, 1989 with the Secretary of State of the
State of Texas (filed as Exhibit 3.1 to Ocean's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1998
and incorporated herein by reference).
4.2 -- Bylaws of Ocean, as amended through March 7, 1997 (filed
as Exhibit 4.9 to Ocean's Registration Statement on Form
S-3 filed with the Securities and Exchange Commission on
September 18, 1997 and incorporated herein by reference).
4.3 -- Amended and Restated Rights Agreement, dated March 17,
1989, as amended effective June 13, 1992 and amended and
restated as of December 12, 1997, between Ocean and
BankBoston, N.A. (as successor to NCNB Texas National
Bank), including Form of Statement of Resolution
Establishing the Series B Junior Participating Preferred
Stock, the Form of Right Certificate and Form of Summary
of Rights to Purchase Preferred Shares (filed as Exhibit
2 to Ocean's Current Report on Form 8-K dated December
15, 1997 and incorporated herein by reference).
4.4 -- Amendment No. 1 to Amended and Restated Rights Agreement
dated November 24, 1998, between Ocean and BankBoston,
N.A. (filed as Exhibit 4.1 to Ocean's Current Report on
Form 8-K filed with the Securities and Exchange
Commission on December 1, 1998 and incorporated herein by
reference).
4.5 -- Amendment No. 2 to Amended and Restated Rights Agreement
dated March 10, 1999, between Ocean and BankBoston, N.A.
(filed as Exhibit 4.1 to Ocean's Current Report on Form
8-K filed with the Securities and Exchange Commission on
March 12, 1999 and incorporated herein by reference).
4.6 -- Amendment No. 3 to Amended and Restated Rights Agreement
dated May 21, 1999, between Ocean and BankBoston, N.A.
(filed as Exhibit 4.1 to Ocean's Current Report on Form
8-K filed with the Securities and Exchange Commission on
May 21, 1999 and incorporated herein by reference).
</TABLE>
<PAGE> 99
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
4.7 -- Revolving Credit Agreement, dated as of March 30, 1999,
among Ocean, Chase Bank of Texas, National Association
("Chase Texas") (Individually and as Administrative
Agent), The Chase Manhattan Bank ("Chase Manhattan") (as
Auction Administrative Agent), Bank of America National
Trust and Savings Association ("Bank of America")
(Individually and as Syndication Agent), Bank One Texas,
N. A. ("Bank One") (Individually and as Documentation
Agent), Societe Generale, Southwest Agency ("Societe
Generale") (Individually and as Managing Agent), the Bank
of Montreal (Individually and as Managing Agent), and the
other Banks signatory thereto.
4.8 -- 364-day Credit Agreement, dated as of March 30, 1999,
among Ocean, Chase Texas (Individually and as
Administrative Agent), Chase Manhattan (as Auction
Administrative Agent), Bank of America (Individually and
as Syndication Agent), Bank One (Individually and as
Documentation Agent), Societe Generale (Individually and
as Managing Agent), the Bank of Montreal (Individually
and as Managing Agent), and the other Banks signatory
thereto.
*4.9 -- Ocean Energy Royalty Trust -- Trust Agreement.
**4.10 -- Ocean Energy Royalty Trust -- Amended and Restated Trust
Agreement.
*4.11 -- Ocean Energy Royalty Trust -- Certificate of Trust.
4.12 -- Indenture, dated as of July 8, 1998, among Ocean Energy,
Inc., its Subsidiary Guarantors, and U.S. Bank Trust
National Association, relating to the 8 3/8% Series A
Senior Subordinated Notes due 2008 and the 8 3/8% Series
B Senior Subordinated Notes due 2008, as amended by First
Supplemental Indenture dated March 30, 1999, incorporated
by reference to Exhibit 10.22 to the Form 10-Q for the
period ended June 30, 1998 of Ocean Energy, Inc.
(Registration No. 0-25058) filed with the Securities and
Exchange Commission on August 14, 1998 and, with respect
to the First Supplemental Indenture, to Exhibit 4.3 to
the Registrant's Form 10-Q for the period ended March 31,
1999.
4.13 -- Indenture, dated as of July 8, 1998, among Ocean Energy,
Inc., its Subsidiary Guarantors, and Norwest Bank
Minnesota, National Association (Norwest Bank) as
Property trustee, relating to the 7 5/8% Senior Notes due
2005, as amended by First Supplemental Indenture dated
March 30, 1999, incorporated by reference to Exhibit
10.23 to the Form 10-Q for the period ended June 30, 1998
of Ocean Energy, Inc. (Registration No. 0-25058) filed
with the Securities and Exchange Commission on August 14,
1998 and, with respect to the First Supplemental
Indenture, to Exhibit 4.4 to the Registrant's Form 10-Q
for the period ended March 31, 1999.
4.14 -- Indenture, dated as of July 8, 1998, among Ocean Energy,
Inc., its Subsidiary Guarantors, and Norwest Bank as
Property trustee, relating to the 8 1/4% Senior Notes due
2018, as amended by First Supplemental Indenture dated
March 30, 1999, incorporated by reference to Exhibit
10.24 to the Form 10-Q for the period ended June 30, 1998
of Ocean Energy, Inc. (Registration No. 0-25058) filed
with the Securities and Exchange Commission on August 14,
1998 and, with respect to the First Supplemental
Indenture, to Exhibit 4.5 to the Registrant's Form 10-Q
for the period ended March 31, 1999.
</TABLE>
<PAGE> 100
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
4.15 -- Indenture, dated as of July 2, 1997, among Ocean Energy,
Inc., the Subsidiary Guarantors Named Therein and State
Street Bank and Trust Company, as Property trustee,
relating to the 8 7/8% Senior Subordinated Notes due 2007
(the Indenture is incorporated by reference to Exhibit
4.1 to the Registration Statement on Form S-4 (No.
333-32715) of Ocean Energy, Inc. filed with the SEC on
August 1, 1997; the First Supplemental Indenture, dated
as of March 27, 1998, is incorporated by reference to
Exhibit 10.11 to the Form 8-K of Ocean Energy, Inc.
(Registration No. 0-25058) filed with the Securities and
Exchange Commission on March 31, 1998); and the Second
Supplemental Indenture dated March 30, 1999 is
incorporated by reference to Exhibit 4.6 to the
Registrant's Form 10-Q for the period ended March 31,
1999.
4.16 -- Indenture, dated as of September 26, 1996, among Ocean
Energy, Inc. (f/k/a Flores & Rucks, Inc.), the Subsidiary
Guarantors Named Therein and Fleet National Bank, as
Property trustee, relating to the 9 3/4% Senior
Subordinated Notes Due 2006 (the Indenture is
incorporated by reference to Exhibit 4.1 to the Quarterly
Report on Form 10-Q for the quarter ended September 30,
1996 of Ocean Energy, Inc. (Registration No. 0-25058);
the First Supplemental Indenture, dated as of March 27,
1998, is incorporated by reference to Exhibit 10.10 to
the Form 8-K of Ocean Energy, Inc. (Registration No.
0-25058) filed with the Securities and Exchange
Commission on March 31, 1998; and the Second Supplemental
Indenture dated March 30, 1999 is incorporated by
reference to Exhibit 4.7 to the Registrant's Form 10-Q
for the period ended March 31, 1999.
4.17 -- Indenture, dated as of October 30, 1995, among Ocean
Energy, Inc., a Delaware corporation (successor by merger
to United Meridian Corporation), Ocean Energy, Inc., a
Louisiana corporation (successor by merger to UMC
Petroleum Corporation) and Bank of Montreal Trust
Company, as Property trustee, relating to the 10 3/8%
Senior Subordinated Notes Due 2005 (the Indenture is
incorporated by reference to Exhibit 4.20 to UMC's Annual
Report on Form 10-K for the year ended December 31, 1995;
the First Supplemental Indenture, dated as of November 4,
1997, is incorporated by reference to Exhibit 4.11 to the
Form 10-Q for the quarter ended September 30, 1998 of
Ocean Energy, Inc. (Registration No. 0-25058); the Second
Supplemental Indenture, dated as of March 27, 1998, is
incorporated by reference to Exhibit 10.12 to the Form
8-K of Ocean Energy, Inc. (Registration No. 0-25058)
filed with the Securities and Exchange Commission on
March 31, 1998); and the Third Supplemental Indenture
dated March 30, 1999 is incorporated by reference to
Exhibit 4.8 to the Registrant's Form 10-Q for the period
ended March 31, 1999.
</TABLE>
<PAGE> 101
<TABLE>
<CAPTION>
EXHIBIT NO.
-----------
<C> <S>
4.18 -- Indenture, dated as of December 1, 1994, among Ocean
Energy, Inc. (f/k/a Flores & Rucks, Inc.), the Subsidiary
Guarantors Named Therein and Chimed Bank Connecticut,
National Association, as Property trustee, relating to
the 13 1/2% Senior Notes Due 2004, (the Indenture is
incorporated by reference to Exhibit 4.1 to the Annual
Report on Form 10-K for the year ended December 31, 1994
of Ocean Energy, Inc. (Registration No. 0-25058); the
First Supplemental Indenture, dated as of September 19,
1996, is incorporated by reference to Exhibit 4.1 to the
Form 8-K of Ocean Energy, Inc. (Registration No. 0-25058)
filed with the Securities and Exchange Commission on
October 10, 1996; the Second Supplemental Indenture,
dated as of July 14, 1997, is incorporated by reference
to Exhibit 4.1 to the Quarterly Report on Form 10-Q for
the quarter ended September 30, 1997 of Ocean Energy,
Inc. (Registration No. 0-25058); the Third Supplemental
Indenture, dated as of March 27, 1998, is incorporated by
reference to Exhibit 10.9 to the Form 8-K of Ocean
Energy, Inc. (Registration No. 0-25058) filed with the
Securities and Exchange Commission on March 31, 1998);
and the Fourth Supplemental Indenture dated March 30,
1999 is incorporated by reference to Exhibit 4.9 to the
Registrant's Form 10-Q for the period ended March 31,
1999.
**5.1 -- Opinion of Richards, Layton & Finger, P.A. as to the
validity of the securities offered hereby.
**8.1 -- Opinion of Vinson & Elkins L.L.P. regarding federal
income tax matters.
**10.1 -- Form of Net Overriding Royalty Conveyance -- Arkansas.
**10.2 -- Form of Net Overriding Royalty Conveyance -- Montana.
**10.3 -- Form of Net Overriding Royalty Conveyance -- Oklahoma.
*23.1 -- Consent of KPMG LLP.
*23.2 -- Consent of Arthur Andersen LLP.
*23.3 -- Consent of Miller & Lents.
*23.4 -- Consent of DeGolyer and MacNaughton.
*23.5 -- Consent of Netherland, Sewell & Associates, Inc.
*23.6 -- Consent of Ryder Scott Company Petroleum Engineers.
*23.7 -- Consent of McDaniel & Associates Consultants Ltd.
*23.8 -- Consent of Netherland, Sewell & Associates, Inc. -- Ocean
Energy, Inc. (Delaware).
*23.9 -- Consent of Ryder Scott Company Petroleum
Engineers -- Ocean Energy, Inc. (Delaware).
**23.10 -- Consent of Richards, Layton & Finger, P.A. (included in
the opinion filed as Exhibit 5.1 of this Registration
Statement).
**23.11 -- Consent of Vinson & Elkins L.L.P. (included in the
opinion filed as Exhibit 8.1 of this Registration
Statement).
**24.1 -- Power of Attorney (included in the signature page of this
Registration Statement).
</TABLE>
- - ---------------
* Filed herewith.
** To be filed by amendment.
<PAGE> 1
EXHIBIT 4.9
TRUST AGREEMENT
OF
OCEAN ENERGY ROYALTY TRUST
THIS TRUST AGREEMENT OF OCEAN ENERGY ROYALTY TRUST is made as of July
14, 1999 (this "Trust Agreement"), by and among Ocean Energy Inc., a Delaware
corporation, as sponsor (the "Sponsor"), Bank One, Texas, N.A., a national
banking association, as property trustee, and Bank One Delaware, Inc., a
Delaware corporation, as Delaware trustee, (collectively, the "Trustees"). The
Sponsor and the Trustees hereby agree as follows:
1. The trust created hereby shall be known as "Ocean Energy Royalty
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 $10. 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.
ss. 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 or obligation
hereunder or with respect of 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 "Commission") 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 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,
<PAGE> 2
certificates, agreements and other instruments as shall be necessary or
desirable to cause the trust securities of the Trust to be listed on the New
York Stock Exchange 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; and (v) 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 Commission, the New York Stock Exchange 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 New York
Stock Exchange or other exchange, NASD, or state securities or "blue sky" laws;
provided, however, that the Trustees in their discretion may resign if they
elect not to join in any such filing or to execute any such document.
5. This 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 thirty days' prior notice to the Sponsor.
7. Bank One Delaware, Inc., in its capacity as Delaware Trustee of the
Trust, shall not have any of the powers or duties of the Trustees set forth
herein and shall be a Trustee of the Trust for the sole purpose of satisfying
the requirements of Section 3807 of the Business Trust Act.
8. 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 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,
-2-
<PAGE> 3
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.
9. The Trust may be dissolved and terminated before the issuance of the
trust securities of the Trust at the election of the Sponsor.
10. This 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).
IN WITNESS WHEREOF, the parties hereto have caused this Trust Agreement
to be duly executed as of the day and year first above written.
Ocean Energy Inc., as Sponsor
By: /s/ Robert K. Reeves
----------------------------------------
Name: Robert K. Reeves
Title: Executive Vice President, General
Counsel and Secretary
Bank One, Texas, N.A., as property trustee
By: /s/ Susan Brem
----------------------------------------
Name: Susan Brem
Title: Assistant Vice President
Bank One Delaware, Inc., as Delaware
trustee
By: /s/ Steve Wagner
----------------------------------------
Name: Steve Wagner
Title: Vice President
-3-
<PAGE> 1
EXHIBIT 4.11
CERTIFICATE OF TRUST
OF
OCEAN ENERGY ROYALTY TRUST
THIS Certificate of Trust of Ocean Energy Royalty Trust (the
"Trust"), dated as of July 14, 1999, is being duly executed and filed by the
undersigned, as trustees, to form a business trust under the Delaware Business
Trust Act (12 Del. C. Section 3801, et seq.).
1. Name. The name of the business trust formed hereby is Ocean
Energy Royalty Trust.
2. Delaware Trustee. The name and business address of the
Delaware trustee of the Trust with a principal place of business in the State of
Delaware are Bank One Delaware, Inc. and Three Christina Centre, 201 North
Walnut Street, Wilmington, Delaware 19801.
3. Effective Date. This Certificate of Trust shall be
effective upon filing with the Secretary of the State of the State of Delaware.
IN WITNESS WHEREOF, the undersigned, being the trustees of the
Trust, have executed this Certificate of Trust as of the date first-above
written.
Bank One, Texas, N.A., as trustee
By: /s/ SUSAN BREM
---------------------------------
Name: Susan Brem
Title: Assistant Vice President
Bank One Delaware, Inc., as trustee
By: /s/ STEVE WAGNER
---------------------------------
Name: Steve Wagner
Title: Vice President
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT AUDITORS
The Board of Directors
Ocean Energy, Inc.:
We consent to the use of our report dated July 12, 1999 relating to the
statements of revenues and direct operating expenses of the Underlying
Properties of Ocean Energy, Inc. for each of the years in the three-year period
ended December 31, 1998 included herein, and to the use of our report dated
February 9, 1999, relating to the consolidated balance sheets of Ocean Energy,
Inc. and Subsidiaries (formerly Seagull Energy Corporation) as of December 31,
1998 and 1997 and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the years in the three-year
period ended December 31, 1998, which report is included in the December 31,
1998 Annual Report on Form 10-K of Seagull Energy Corporation incorporated
herein by reference, and to the reference to our firm under the heading
"Experts" in the prospectus.
KPMG LLP
Houston, Texas
July 14, 1999
<PAGE> 1
EXHIBIT 23.2
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference in this registration statement of our report dated February 15, 1999,
included in the Ocean Energy, Inc. Annual Report on Form 10-K for the fiscal
year ended December 31, 1998, and incorporated by reference in the Ocean Energy
Inc. Form 8-K filed April 9, 1999, and to all references to our Firm included in
this registration statement.
ARTHUR ANDERSEN LLP
Houston, Texas
July 14, 1999
<PAGE> 1
EXHIBIT 23.3
[MILLER AND LENTS, LTD. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the incorporation by reference of Miller and Lents,
Ltd. into Ocean Energy Royalty Trust's Registration Statement on Form S-1 and
Ocean Energy, Inc.'s Registration Statement on Form S-3 to which this consent
is an exhibit. We further consent to the reference to our firm under the
heading "Experts" in the Registration Statement.
MILLER AND LENTS, LTD.
By /s/ GREGORY W. ARMES
------------------------------
Gregory W. Armes
Senior Vice President
Houston, Texas
July 14, 1999
<PAGE> 1
EXHIBIT 23.4
[DEGOLYER AND MACNAUGHTON LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the incorporation by reference of our name in the
Annual Report on Form 10-K of Seagull Energy Corporation and subsidiaries for
the year ended December 31, 1998, into Ocean Energy Royalty Trust's Registration
Statement on Form S-1 and Ocean Energy, Inc.'s (formerly known as Seagull Energy
Corporation) Registration Statement on Form S-3 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/ DEGOLYER AND MACNAUGHTON
DeGOLYER and MacNAUGHTON
Dallas, Texas
July 14, 1999
<PAGE> 1
EXHIBIT 23.5
[NETHERLAND, SEWELL & ASSOCIATES, INC. LETTERHEAD]
CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.
We hereby consent to the incorporation by reference of our Firm's name in
the Annual Report on Form 10-K of Seagull Energy Corporation and subsidiaries
for the year ended December 31, 1998, into Ocean Energy Royalty Trust's
Registration Statement on Form S-1 and Ocean Energy, Inc.'s (formerly known as
Seagull Energy Corporation) Registration Statement on Form S-3 to which this
consent is an exhibit. We further consent to the reference to our firm under
the heading "Experts" in the Registration Statement.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ DANNY D. SIMMONS
---------------------------------------
Danny D. Simmons
Senior Vice President
Houston, Texas
July 14, 1999
<PAGE> 1
EXHIBIT 23.6
[RYDER SCOTT COMPANY LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM
ENGINEERS AND GEOLOGISTS
We hereby consent to the incorporation by reference of our Firm's name in the
Annual Report of form 10-K of Seagull Energy Corporation and subsidiaries for
the year ended December 31, 1998, into Ocean Energy Royalty Trust's Registration
Statement on Form S-1 and Ocean Energy, Inc.'s (formerly known as Seagull Energy
Corporation) Registration Statement on Form S-3 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.
----------------------------
RYDER SCOTT COMPANY, L.P.
Houston, Texas
July 14, 1999
<PAGE> 1
EXHIBIT 23.7
[McDANIEL & ASSOCIATES CONSULTANTS LTD. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM
ENGINEERS AND GEOLOGISTS
We hereby consent to the incorporation by reference of our Firm's name in the
Annual Report on Form 10-K of Ocean Energy, Inc. and subsidiaries for the year
ended December 31, 1998, into Ocean Energy Royalty Trust's Registration
Statement on Form S-1 and Ocean Energy, Inc.'s Registration Statement on Form
S-3 to which this consent is an exhibit. We further consent to the reference to
our firm under the heading "Experts" in the Registration Statement.
Sincerely,
McDANIEL & ASSOCIATES CONSULTANTS, LTD.
/s/ P. A. WELCH
- - --------------------------------------
P. A. Welch, P. Eng.
Senior Vice President
Calgary, Alberta
July 14, 1999
<PAGE> 1
EXHIBIT 23.8
[NETHERLAND, SEWELL & ASSOCIATES, INC. LETTERHEAD]
CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.
We hereby consent to the incorporation by reference of our Firm's name in
the Annual Report on Form 10-K of Ocean Energy, Inc. and subsidiaries for the
year ended December 31, 1998, into Ocean Energy Royalty Trust's Registration
Statement on Form S-1 and Ocean Energy, Inc.'s Registration Statement on Form
S-3 to which this consent is an exhibit. We further consent to the reference to
our firm under the heading "Experts" in the Registration Statement.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ DANNY D. SIMMONS
-------------------------
Danny D. Simmons
Senior Vice President
Houston, Texas
July 14, 1999
<PAGE> 1
EXHIBIT 23.9
[RYDER SCOTT COMPANY LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM
ENGINEERS AND GEOLOGISTS
We hereby consent to the incorporation by reference of our Firm's name in
the Annual Report on Form 10-K of Ocean Energy, Inc. and subsidiaries for the
year ended December 31, 1998, into Ocean Energy Royalty Trust's Registration
Statement on Form S-1 and Ocean Energy, Inc.'s Registration Statement on Form
S-3 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.
RYDER SCOTT COMPANY, L.P.
Houston, Texas
July 14, 1999
