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U.S. Securities and Exchange Commission
Washington, D.C. 20549
FORM 10-KSB
(Mark One)
[ X ] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 333-62167
Atlas-Energy for the Nineties-Public #7 Ltd.
(Name of small business issuer in its charter)
Pennsylvania 25-1814688
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
311 Rouser Road, Moon Township, Pennsylvania 15108
(Address of principal executive offices) (Zip Code)
Issuer's telephone number (412) 262-2830
Securities registered under Section 12(b) of the Exchange Act
Title of each class Name of each exchange on which registered
None None
Securities registered under Section 12(g) of the Exchange Act
None
(Title of Class)
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such
shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes X No
---- ----
Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. [ X ]
State issuer's revenues for its most recent fiscal year. $1,572,646
State the aggregate market value of the voting stock held by
non-affiliates of the Registrant. Not Applicable.
Transitional Small Business Disclosure Format (check one):
Yes No X
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PART I
ITEM 1. DESCRIPTION OF BUSINESS ATLAS-ENERGY FOR THE NINETIES-PUBLIC #7 LTD.
(THE "PARTNERSHIP")
We were formed under the Pennsylvania Revised Uniform Limited
Partnership Act on July 16, 1998, with Atlas Resources, Inc. ("Atlas") as our
managing general partner to drill natural gas development wells. We have no
employees and rely on our managing general partner for management. See Item 9
"Directors, Executive Officers and Significant Employees, Compliance With
Section 16(A) of the Exchange Act."
We began our drilling activities under the drilling and operating
agreement, with our managing general partner acting as operator and general
drilling contractor, on our initial closing date of December 1, 1998. Our final
closing date was December 31, 1998, and we were funded with total subscriptions
of $11,988,350. We paid drilling costs under the drilling and operating
agreement in an amount equal to $11,988,350.
A total of 57.5 net development wells were drilled and completed to the
Clinton/Medina geological formation in Pennsylvania and Ohio. These wells are
currently producing natural gas, which is our only product, and will continue
to do so until they are depleted at which time they will be plugged and
abandoned. No other wells will be drilled and thus no additional funds will
be required for drilling. Also, we did not begin paying operating and
maintenance costs for the wells under the drilling and operating agreement
until the wells began to produce, and our operating and maintenance costs
have been and are expected to be fulfilled through revenues generated from
our gas sales. During producing operations our managing general partner, as
operator, receives a monthly well supervision fee of $275 for each producing
well for which it has responsibility under the drilling and operating
agreement. The well supervision fee covers all normal and regularly recurring
operating expenses for the production, delivery and sale of gas, such as:
- well tending, routine maintenance and adjustment;
- reading meters, recording production, pumping, maintaining
appropriate books and records;
- preparing reports to us and to government agencies; and
- collecting and disbursing revenues.
The well supervision fees do not include costs and expenses related to
the purchase of equipment, materials or third party services and brine disposal.
If these costs are incurred, then our managing general partner as operator will
charge us at cost for third party services and materials and a reasonable charge
for services performed directly by it or its affiliates. The drilling and
operating agreement also gives our managing general partner as operator the
right at any time after three years from the date one of our wells has been
placed into production to retain $200 per month to cover future plugging and
abandonment costs of the well. Although we do not anticipate that we will have
to do so, any additional funds which may be required will be obtained from
production revenues or borrowings from our managing general partner or its
affiliates, which are not contractually committed to make a loan. The amount
that may be borrowed may not at any tine exceed 5% of our total subscriptions,
and no borrowings will be obtained from third parties.
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We did not purchase and do not anticipate selling any producing wells. To
realize revenues our natural gas must be marketed. Our managing general partner
is responsible for selling our gas production, and its policy is to treat all
wells in a given geographic area equally. Our managing general partner
determines a weighted average selling price for all the gas sold in a geographic
area, such as the Mercer County area, by taking the money received from the sale
of all the gas sold by it and its affiliates, including us, in the area and
dividing by the volume of gas sold. Each of the managing general partner's
affiliates, including us, will then receive this gas price for all gas sold in
the area. All of our gas is to be sold as discussed in Item 2, "Properties -
Delivery Commitments."
The marketing of our gas production is also affected by numerous factors
beyond our control and the effect of which we cannot accurately predict. These
factors include, but are not limited to, the following:
- the amount of domestic production and foreign imports of oil and
gas;
- competition from other energy sources such as coal and nuclear
energy;
- local, state and federal regulations regarding production and the
cost of complying with applicable environmental regulations; and
- fluctuating seasonal supply and demand.
For example, the demand for natural gas is greater in the winter months than in
the summer months, which is reflected in a higher spot market price paid for the
gas. Also, increased imports of oil and natural gas have occurred and are
expected to continue. The free trade agreement between Canada and the United
States eased restrictions on imports of Canadian gas to the United States, and
the North American Free Trade Agreement eliminated trade and investment barriers
in the United States, Canada and Mexico. These imports could have an adverse
effect on both the price and volume of gas produced from the wells. In the past
reduced demand for natural gas and/or an excess supply of gas resulted in a
lower price paid for gas and difficulties in marketing gas.
Governmental agencies regulate the production and transportation of our
natural gas. Generally, the regulatory agency in the state where a producing
natural gas well is located supervises production activities and the
transportation of natural gas sold intrastate. Our oil and gas operations are
regulated in Pennsylvania by the Department of Environmental Resources, Division
of Oil and Gas and in Ohio by the Ohio Department of Natural Resources, Division
of Oil and Gas which impose a comprehensive statutory and regulatory scheme on
oil and gas operations such as ours. Among other things, the regulations
involve:
- new well permit and well registration requirements, procedures and
fees;
- minimum well spacing requirements;
- restrictions on well locations and underground gas storage;
- certain well site restoration, groundwater protection and safety
measures;
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- landowner notification requirements;
- certain bonding or other security measures;
- various reporting requirements;
- well plugging standards and procedures; and
- broad enforcement powers.
We do not expect that these regulations will have a material adverse impact upon
our operations, and we believe we have complied in all material respects with
applicable state regulations and will continue to do so.
Gas prices are not regulated and in recent years gas prices have been
volatile. The price of our gas is based on supply, demand, BTU content,
pressure, location of the well and other factors.
The Federal Energy Regulatory Commission ("FERC") regulates the
interstate transportation of natural gas, and it has sought to promote greater
competition in natural gas markets. Traditionally, natural gas has been sold by
gas producers to pipeline companies, which then would resell the gas to
end-users. FERC changed this market structure by requiring interstate pipeline
companies that transport gas for others to provide transportation services to
producers, distributors, and all other shippers of natural gas on a "first-come,
first-served" basis. This permits producers and other shippers to sell natural
gas directly to end-users and local distribution companies.
FERC Order 636 requires gas pipeline companies to, among other things,
separate their sales services from their transportation services and provide an
open access transportation service that is comparable in quality for all gas
suppliers or producers. The premise behind FERC Order 636 was that the gas
pipeline companies had an unfair advantage over other gas suppliers because they
could bundle their sales and transportation services together. FERC Order 636 is
designed to ensure that no gas seller has a competitive advantage over another
gas seller because it also provides transportation services. We believe the
effect of FERC Order 636 has been to restructure the natural gas industry and
increase its competitiveness. Also, the Clean Air Act Amendments of 1990 contain
incentives for the future development of "clean alternative fuel," which
includes natural gas and liquefied petroleum gas for "clean-fuel vehicles." We
believe the amendments ultimately will have a beneficial effect on natural gas
markets and prices.
Oil prices are not regulated and the price is subject to supply, demand,
competitive factors, the gravity of the crude oil, sulfur content differentials
and other factors. We expect to sell only small quantities of oil, if any.
From time to time there are a number of proposals being considered in
Congress and in the legislatures and agencies of various states that if enacted
would significantly and adversely affect the oil and natural gas industry,
including us. The proposals involve, among other things, limiting the disposal
of waste water from wells and changes in the tax laws. We are unable to predict
what proposals, if any, will be enacted and their subsequent effect on our
activities.
Our operations and costs may also be affected by various federal, state
and local laws covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment. We
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may generally be liable for cleanup costs to the United States Government under
the Federal Clean Water Act for oil or hazardous substance pollution and for
hazardous substance contamination under the Comprehensive Environmental
Response, Compensation and Liability Act of 1980. Our liability for
environmental cleanup costs or damages is unlimited in cases of willful
negligence or misconduct. In addition, the Environmental Protection Agency will
require us to prepare and implement spill prevention control and countermeasure
plans relating to the possible discharge of oil into navigable waters and will
require permits to authorize the discharge of pollutants into navigable waters.
State and local permits or approvals will also be needed with respect to
wastewater discharges and air pollutant emissions.
Violations of environment-related lease conditions or environmental
permits can result in substantial civil and criminal penalties as well as
potential court injunctions curtailing operations. Compliance with these
statutes and regulations may cause delays or increase our production costs.
Because these laws and regulations are constantly being revised and changed we
are unable to predict the ultimate costs of complying with present and future
environmental laws and regulations, although we do not believe these costs will
be substantial. We are unable to obtain insurance to protect against many
environmental claims.
We have not filed bankruptcy nor have we been involved in any material
reclassification, merger, consolidation, receivership or similar proceeding or
purchase or sale of a significant amount of assets not in the ordinary course of
business. Also, we have not and will not devote any funds to research and
development activities and there are no new products or services. We do not have
any patents, trademarks, licenses, franchises, concessions, royalty agreements
or labor contracts.
ITEM 2. PROPERTIES
DRILLING ACTIVITY. We drilled 57.5 net wells and all were productive. The
wells were completed by April 28, 1999. No further drilling activities will be
undertaken.
The following table summarizes our drilling activity since our formation.
All the wells drilled were development wells which means a well drilled within
the proved area of an oil or gas reservoir to the depth of a stratigraphic
horizon known to be productive. We did not participate in any exploratory wells
which means a well drilled to find commercially productive hydrocarbons in an
unproved area; to find a new commercially productive horizon in a field
previously found to be productive of hydrocarbons at another horizon; or to
significantly extend a known prospect.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1998 1999
---- ----
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
Development Wells:
Oil..................................... 0 0 0 0
Gas..................................... 0 0 64 57.5
Dry..................................... 0 0 0 0
------ ------ ------ ------
Total............................... 0 0 64 57.5
====== ====== ====== ======
</TABLE>
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A "dry hole" is an exploratory or a development well found to be
incapable of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well. A "productive well" is an exploratory or a
development well that is not a dry well.
A "gross" well is a well in which we have a working interest. A "net"
well equals the actual working interest owned in one gross well divided by one
hundred. For example, a 50% working interest in a well is one gross well, but a
.50 net well.
PRODUCTION. The following table shows our net production in barrels
("bbls") of crude oil and in thousands of cubic feet ("mcf") of natural gas and
the costs and weighted average selling prices thereof, for the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1998 1999
---- ----
<S> <C> <C>
Production (1):
Oil (Bbls).................................... 0 0
Natural Gas (Mcf)............................. 0 662,125
Total (Equivalent Barrels) (2)............... 0 110,354
Average Sales Price:
Per Equivalent Barrel (2)(3).................. 0 $14.16
Average Production Cost (lifting cost):
Per Equivalent Barrel (2)(4).................. 0 $2.36
</TABLE>
(1) The production shown in the table is determined by multiplying
the gross production of properties in which we have an interest by
the percentage of the leasehold interest we own less the royalty
interests of others. All of the wells we own other than two are
subject to a 12.5% landowner's royalty and have an 87.5% net
revenue interest. Of the two remaining wells, one well is also
subject to a 3.125% overriding royalty interest and has an 84.375%
net revenue interest, and the other well has a second overriding
royalty interest of 2.5% and has an 85% net revenue interest.
(2) The ratio of energy content of oil and gas (six mcf of gas equals
one barrel of oil) was used to convert natural gas production into
equivalent barrels of oil.
(3) The average sales price per mcf of gas sold by us was $2.36 in
1999 after deducting all expenses, including transportation
expenses.
(4) Production costs represent oil and gas operating expenses as
reflected in our financial statements plus depreciation of support
equipment and facilities.
SUMMARY OF PRODUCTIVE WELLS. The table below gives the number of our
productive gross and net wells at December 31, 1999.
<TABLE>
<CAPTION>
GAS WELLS
--------------
Location Gross Net
- -------- ----- ---
<S> <C> <C>
Pennsylvania................... 63 57
Ohio........................... 1 .5
---- ----
Total..................... 64 57.5
==== ====
</TABLE>
"Productive wells" are producing wells and wells capable of production.
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OIL AND GAS RESERVES. All of our oil and gas reserves are located in the
United States. Estimates of our net proved developed and undeveloped oil and gas
reserves as of December 31, 1999, and the present value (discounted at 10%) of
estimated future net revenue before income tax from those reserves are set forth
in the following table. This information is derived from the engineering report
dated January 1, 2000.
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1999 PRESENT VALUE OF
NET PROVED RESERVES FUTURE NET REVENUES
------------------------- --------------------
Oil Gas Total
(Bbls) (Mcf) (BOE) (in thousands)
------ ----- -----
<S> <C> <C> <C> <C>
Proved Developed.................... 0 4,611,849 768,642 $ 3,995
Proved Undeveloped.................. 0 0 0 0
--------- --------- --------- --------
Total 0 4,611,849 768,642 $ 3,995
========= ========= ========= ========
</TABLE>
Estimated future net revenues represent estimated future gross revenues
from the production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of December 31, 1999.
These prices were held constant throughout the life of the properties except
where different prices were fixed and determinable from applicable contracts.
These price assumptions resulted in a weighted average price of $2.92 per mcf
for gas over the life of the properties. The amounts shown do not reflect
non-property related costs, such as:
- general and administrative expenses;
- future income tax expense; and
- depreciation, depletion and amortization.
The present value of estimated future net revenues is calculated by discounting
estimated future net revenues by 10% annually. Prices used in calculating the
estimated future net revenues attributable to proved reserves do not necessarily
reflect market prices for oil and gas production after December 31, 1999. We can
provide no assurance of the following:
- that all of the proved reserves will be produced and sold within
the periods assumed;
- that the assumed prices will actually be realized for the
production; or
- that existing contracts will be honored.
The values expressed are estimates only, and may not reflect realizable values
or fair market values of the oil and gas ultimately extracted and recovered. The
standardized measure of discounted future net cash flows may not accurately
reflect proceeds of production to be received in the future from the sale of oil
and gas currently owned and does not necessarily reflect the actual costs that
would be incurred to acquire equivalent oil and gas reserves. For additional
information concerning oil and gas reserves and activities, see Note 9 to
the Financial Statements.
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"Proved reserves" means 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 by contractual arrangements, but not
escalations based upon future conditions.
- 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:
- that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any; and
- 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.
- 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.
- Estimates of proved reserves do not include the following:
- oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves";
- 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;
- crude oil, natural gas, and natural gas liquids, that may
occur in undrilled prospects; and
- crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such
sources.
"Proved developed oil and gas reserves" means 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.
We do not have any proved undeveloped reserves. "Proved undeveloped
reserves" are reserves that are expected to be recovered either from:
- new wells on undrilled acreage; or
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- from existing wells where a relatively major expenditure is
required for recompletion.
Reserves on undrilled acreage are 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 tests
in the area and in the same reservoir.
Since December 31, 1999, we do not believe there has been a favorable or
adverse event which would cause a significant change in estimated reserves.
Reserves cannot be measured exactly as reserve estimates involve subjective
judgment. The estimates must be reviewed periodically and adjusted to reflect
additional information gained from reservoir performance, new geological and
geophysical data and economic changes. We have not filed any estimates (on a
consolidated basis) of our oil and gas reserves with, nor were such estimates
included in any reports to, any Federal or foreign governmental agency other
than the SEC within the 12 months before the date of this filing.
ACREAGE. The following table sets forth, as of December 31, 1999, the
acres of developed and undeveloped oil and gas acreage in which we have an
interest.
<TABLE>
<CAPTION>
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL
----------------- ------------------- ------------------------
Location Gross Net Gross Net Gross Net
- -------- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Pennsylvania................. 3,050 2,800 0 0 3,050 2,800
----- ----- ----- -----
Ohio......................... 150 75 0 0 150 75
----- ----- ----- -----
Total ............ 3,200 2,875 0 0 3,200 2,875
===== ===== ====== ====== ===== =====
</TABLE>
A "gross" acre is an acre in which we own a working interest. A "net"
acre equals the actual working interest owned in one gross acre divided by one
hundred. For example, a 50% working interest in an acre is one gross acre, but a
.50 net acre. "Undeveloped acreage" is those lease acres on which wells have not
been drilled or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether or not such acreage
contains proved reserves.
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DELIVERY COMMITMENTS. Our Managing General Partner anticipates that
substantially all of the natural gas produced by us in this and previous
programs in the Mercer County area will be sold to four (4) customers:
1) National Fuel Resources, Inc, a marketing subsidiary of National
Fuel Gas Company (NFG) a publicly traded natural gas utility
company listed on the New York Stock Exchange. NFG distributes
natural gas to approximately 731,000 customers in southwestern New
York and northwestern Pennsylvania through its regulated utility
divisions.
2) Northeast Ohio Gas Marketing, Inc., a marketing subsidiary of
First Energy Corporation (FE), a publicly traded electric utility
company listed on the New York Stock Exchange. FE serves more than
5.5 million people in central and northern Ohio and western
Pennsylvania.
3) NUI Energy Brokers, Inc, a marketing subsidiary of NUI Corp.
(NUI), a publicly traded natural gas utility company listed on the
New York Stock Exchange. NUI distributes natural gas to
approximately 372,000 customers in six states through its
regulated utility divisions.
4) Wheatland Tube Company, a Pennsylvania Corporation, which connects
directly to Atlas Pipeline Partners (APL), a Master Limited
Partnership, publicly traded on the American Stock Exchange. APL
is engaged in the ownership and operation of the majority of the
natural pipeline gathering systems that serve the managing General
Partner's production affiliates.
All four (4) of the aforementioned Agreements involve monthly pricing
determined by industry standard index for each of the delivery locations
contemplated therein. In addition, the Agreement with Wheatland Tube Company
contains minimum and maximum prices which are fixed over each annual period.
The Agreements with National Fuel Resources, Inc. and NUI Energy
Brokers, Inc. are standard industry contracts as suggested by the Gas
Industry Standards Board (GISB) for one-year terms commencing April 1, 2000.
Both Agreements are for firm fixed daily volumes (11,000 and 5,000 Dthd,
respectively) delivered to the facilities of National Fuel Gas Supply.
The Agreement with Northeast Ohio Gas Marketing, Inc. is for a 10-year
term, which began on April 1, 1999, and provides that Northeast Ohio Gas
Marketing must take all of the gas produced by our managing general partner and
its affiliates. The agreement establishes price formula for each of the
delivery points for either the first one or two years of the Agreement. If, at
the end of the applicable period, our managing general partner and Northeast
Ohio Gas Marketing cannot agree to a new price, then our managing general
partner and its affiliates may arrange a sale of the gas to third parties.
However, they must first give Northeast Ohio Gas Marketing notice and an
opportunity to match the price. Thereafter, Northeast Ohio Gas Marketing and our
managing general partners will set the prices annually each November 30 subject
to the same terms. However, if there is no price agreement, then we can sell our
gas to third parties for the term of any unmatched third party offer. The
contracts with National Fuel Resources, Inc. and NUI Energy Brokers, Inc. are
pursuant to this right of refusal.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION. There is no established public trading market for
our units and we do not anticipate a market will develop. Our units may be
transferred only in accordance with the provisions of Article 6 of our
partnership agreement. The principal restrictions on transferability are as
follows:
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- the consent of our managing general partner is required; and
- no transfer may be made which would result in materially adverse tax
consequences to us or the violation of federal or state securities
laws.
An assignee may become a substituted limited partner or investor general
partner only upon meeting the following conditions:
- the assignor gives the assignee the right;
- our managing general partner consents to the substitution, which is
in its absolute discretion;
- the assignee pays to us all costs and expenses incurred in
connection with the substitution; and
- the assignee executes and delivers the instruments which are
satisfactory to our managing general partner to effect the
substitution and to confirm the assignee's agreement to be bound by
all terms and provisions of the partnership agreement.
A substitute partner is entitled to all rights attributable to full ownership of
the assigned units, including the right to vote.
HOLDERS. As of December 31, 1999, there were 366 interestholders.
DIVIDENDS. Our managing general partner reviews our accounts quarterly
to determine whether cash distributions are appropriate and the amount to be
distributed, if any. We distribute those funds to you and the other participants
which our managing general partner determines are not necessary for us to
retain. We will not advance or borrow for purposes of distributions if the
amount of the distributions would exceed our accrued and received revenues for
the previous four quarters, less paid and accrued operating costs with respect
to the revenues.
The determination of the revenues and costs will be made in accordance
with generally accepted accounting principles, consistently applied, and cash
distributions to our managing general partner may only be made in conjunction
with distributions to you and the other participants.
During the calendar year ending December 31, 1999, we distributed
$538,787 to you and the other participants and $116,352 to our managing
general partner.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
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MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATIONS
Management's discussion and analysis should be read in conjunction
with the financial statements and notes thereto.
RESULTS OF OPERATIONS
TWELVE MONTHS ENDED DECEMBER 31, 1999
The net loss for the twelve months ended December 31, 1999 was
$7,075,410.
The Partnership commenced production in January, 1999. Natural gas
sales revenue for the twelve months ended December 31, 1999 amounted to
$1,564,581, based on gas production of 662,125 Mcf. The average sales
price for gas production during this period was $2.36/Mcf.
The net loss includes an impairment of oil and gas properties.
This non-cash charge to earnings amounted to $6,600,718. Refer to Note #2
in the Notes to Financial Statements.
QUARTER ENDED DECEMBER 31, 1999
The net loss for the quarter ended December 31, 1999 was $5,561,172.
Natural gas sales revenue for the quarter ended December 31, 1999
amounted to $439,625. Gas production was 96,842 Mcf; and the average
sales price was $2.59/Mcf.
The net loss for the quarter includes an impairment of oil and gas
properties. This non-cash charge to earnings amounted to $6,600,718.
Refer to Note #2 in the Notes to Financial Statements.
FINANCIAL CONDITION
LIQUIDITY
Cash provided by operating activities during the twelve months ended
December 31, 1999 results primarily from sales of natural gas. The
Partnership's working capital increased from $29,592 at December 31, 1998
to $639,715 at December 31, 1999. The increase is attributable to the
commencement of natural gas production for new wells turned on-line
during the year, which resulted in higher receivables in connection with
sales of gas produced.
CAPITAL RESOURCES
There were no new material commitments for capital expenditures
during the period and the Partnership does not expect any in the
foreseeable future.
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ITEM 7. FINANCIAL STATEMENTS
Our Financial Statements for the last fiscal year, together with the
opinion of the accountants thereon, are on pages 20 through 32 of this report.
ITEM 8. CHANGES IN AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
In December 1998, we engaged Grant Thornton, L.L.P., as the independent
certified public accountants to audit our financial statements for the calendar
year ended December 31, 1998. At that time, we chose not to renew the engagement
of McLaughlin & Courson, who previously served as our independent certified
public accountants. The decision to change accountants was approved by our
managing general partner.
During the period since our formation on July 16, 1998, and each
subsequent interim period, there were no disagreements with the former
accountants on any matter of accounting principles or practices, financial
statement disclosure, or auditing scope or procedure, which disagreements, if
not resolved to the satisfaction of the former accountants, would have caused
them to make reference in connection with their report to the subject matter of
the disagreements.
The report of the former principal accountants on our financial
statements since our formation contained no adverse opinion or disclaimer of
opinion, nor was it qualified or modified as to uncertainty, audit scope, or
accounting principles.
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES, COMPLIANCE WITH
SECTION 16(A) OF THE EXCHANGE ACT
RESPONSIBILITIES OF ATLAS. We have no employees and rely on our managing
general partner, which also serves as driller-operator of the wells, for
management. Our managing general partner has complete and exclusive discretion
and control over our operations and activities and makes all of our decisions
affecting the wells which we have developed. Our managing general partner
provides continuing review and analysis of all wells and monitors all
expenditures and commitments made on our behalf. In addition, our managing
general partner performs administrative services relating to our funding and
operation, participant reporting, financial budgeting and record keeping.
13
<PAGE>
Because we have no equity securities registered pursuant to Section 12 of
the Exchange Act, there is no required compliance with Section 16(A) of the
Exchange Act.
BUSINESS OF ATLAS. Our managing general partner was incorporated in 1979
and its affiliate, Atlas Energy Group, Inc., an Ohio corporation, was
incorporated in 1973. As of December 31, 1999, our managing general partner and
its affiliates operated approximately 3,400 oil or natural gas wells located in
Ohio, Pennsylvania, and New York.
On September 29, 1998, Atlas Group, the former parent company of our
managing general partner, merged into Atlas America, Inc., a newly formed
wholly-owned subsidiary of Resource America, Inc. Resource America is a
publicly-traded company principally engaged in real estate finance, equipment
leasing and energy and energy finance. Atlas America is continuing the existing
business of Atlas Group and is headquartered at 311 Rouser Road, Moon Township,
Pennsylvania 15108 which is also the managing general partner's primary office.
The managing general partner and its affiliates under Atlas America
employ a total of approximately 154 persons, consisting of 4 geologists, 9
landmen, 4 engineers, 49 operations staff, 12 accounting, 1 gas marketing, and
18 administrative personnel. The balance of the personnel are engineering,
pipeline and field supervisors.
ORGANIZATIONAL DIAGRAM (1)(2)
----------------------
Resource America, Inc.
----------------------
|
----------------------
Atlas America, Inc.
----------------------
|
----------------------
AIC, Inc.
----------------------
|
<TABLE>
<S> <C> <C> <C> <C> <C>
------------------------------------------------------------------------------------------------------------
| | | | | |
- ----------------- ----------------- ------------- ------------------- ------------------ -------------------
Atlas Resources, Atlas Energy Transatco, Atlas Information Anthem Securities Atlas Energy Group,
Inc., managing Corporation, Inc., which Management, Inc., registered Inc., driller and
general partner, managing general owns 50% of L.L.C., markets broker-dealer operator in Ohio
driller and partner of Topico, information and and dealer-manager -------------------
operator in exploratory operates technology services ------------------ |
Pennsylvania drilling pipeline in ------------------- |
- ----------------- partnerships and Ohio |
| driller and ----------- |
| operator |
| ----------------- |
- ------------------ -----------------
ARD Investments, AED Investments,
Inc. Inc.
- ------------------ -----------------
</TABLE>
- -----------------
(1) Resource Energy and Viking Resources, which are subsidiaries of Resource
America, are also engaged in the oil and gas business. In the near term,
it is expected that both Resource Energy and Viking Resources will retain
their separate corporate existence, however, Atlas America will manage
the assets and employees of both including sharing common employees.
Also, many of the officers and directors of our managing general partner
serve as officers and directors of those entities.
(2) Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating Partnership)
is a master limited partnership formed by a subsidiary of Atlas America
as managing general partner to acquire a natural gas gathering system and
related facilities from Resource Energy, Atlas America, and Viking
Resources. The gathering system consists of approximately 888 miles of
intrastate pipelines located in Pennsylvania, Ohio, and New York. We
anticipate that this master limited partnership will gather and deliver
natural gas produced by us in the Mercer County area to either
public utility or interstate pipeline systems or industrial end-users in
the area.
14
<PAGE>
DIRECTORS, EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES OF ATLAS. The
executive officers, directors and significant employees of our managing general
partner are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION OR OFFICE
- ------------------------ ---- --------------------------------------------------
<S> <C> <C>
James R. O'Mara 57 Vice Chairman of the Board and a Director
Charles T. Koval 66 Director
Tony C. Banks 45 President, Chief Executive Officer, and a Director
Frank P. Carolas 40 Vice President of Land and Geology
Jeffrey C. Simmons 41 Vice President of Production
William R. Seiler 45 Vice President and Controller
Barbara J. Krasnicki 54 Secretary
</TABLE>
JAMES R. O'MARA. Vice Chairman of the Board and a director of the
managing general partner and Atlas America. Mr. O'Mara joined Atlas Energy in
1975.
CHARLES T. KOVAL. Director of the managing general partner and Atlas
America. He co-founded Atlas Energy. Mr. Koval is serving and has served as a
director of Imperial Harbors since 1980.
TONY C. BANKS. President, Chief Executive Officer and a director of the
managing general partner and Atlas America. Mr. Banks joined Atlas Group in
1995. Prior to Mr. Banks joining Atlas he had been with affiliates of
Consolidated Natural Gas Company ("CNG") since 1974. Mr. Banks started as an
accounting clerk with CNG's parent company in 1974 and progressed through
various positions with CNG's Appalachian producer, northeast gas marketer and
southwest producer to his last position as Treasurer of CNG's national energy
marketing subsidiary.
FRANK P. CAROLAS. Vice President of Geology of the managing general
partner and Atlas America. Mr. Carolas joined Atlas Energy in 1981.
JEFFREY C. SIMMONS. Vice President of Operations of the managing general
partner and Atlas America. Since 1997 Mr. Simmons has also been Executive Vice
President, Chief Operating Officer and director of Resource Energy. Mr. Simmons
joined Resource America in 1986 as a senior petroleum engineer.
WILLIAM R. SEILER. Vice President and Controller of the managing general
partner and Atlas America. Mr. Seiler has over 25 years of accounting, financial
reporting, financial analysis, and mergers and acquisitions experience in the
oil and gas industry with Consolidated Natural Gas Company before joining Atlas
America and the managing general partner in July of 1999. Mr. Seiler joined
CNG's corporate headquarters in 1974 as an accounting clerk and progressed to
his final position as an officer of CNG as corporate assistant controller.
BARBARA J. KRASNICKI. Secretary of the managing general partner. Ms.
Krasnicki has been with Atlas America and its predecessors since their inception
in 1971. She was the office and personnel manager. She was elected secretary of
the managing general partner in August, 1999.
15
<PAGE>
ITEM 10. EXECUTIVE COMPENSATION
We have no employees and rely on the employees of the managing general
partner and its affiliates for services. Thus, we did not directly pay any
compensation to the employees of our managing general partner for the last
fiscal year. See Item 12, "Interest of Management and Others in Certain
Transactions," below for compensation which we paid to our managing general
partner.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of December 31, 1999, we had issued and outstanding 1,200 units. No
officer or director of our managing general partner owns any units. Also, no
partner beneficially owns more than 10% of our outstanding units.
Resource America owns 100% of the common stock of Atlas America, which
owns 100% of the common stock of AIC, Inc., which owns 100% of the common stock
of our managing general partner.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
OIL AND GAS REVENUES. Our managing general partner is allocated 31% of
our oil and gas revenues in return for having paid organization and offering
costs equal to 15% of our subscriptions, 51% of tangible costs and contributing
all leases for a total capital contribution of $3,852,439. During the calendar
year ending December 31, 1999, our managing general partner received $404,405
from our oil and gas revenues.
LEASES. Our managing general partner contributed to us (at the lower of
fair market value or its cost of the prospects) 58 undeveloped prospects to
drill approximately 57.5 net wells. Our managing general partner received a
credit in the amount of $208,800 for these prospects. During 1999, our managing
general partner did not enter into any further lease transactions with us and
none are anticipated.
ADMINISTRATIVE COSTS. Our managing general partner and its affiliates
receive an unaccountable, fixed payment reimbursement for their administrative
costs of $75 per well per month, which is proportionately reduced if we acquired
less than 100% of the working interest in a well. During the calendar year
ending December 31, 1999, our managing general partner received $37,628 for
its administrative costs.
DIRECT COSTS. Our managing general partner and its affiliates are
reimbursed for all direct costs expended on our behalf. During the calendar year
ending December 31, 1999, our managing general partner received $126,004 as
reimbursement for direct costs.
DRILLING CONTRACTS. On December 1, 1998, as amended on December 31, 1998,
we entered into a drilling contract with our managing general partner to drill
and complete 57.5 net wells. We paid the
16
<PAGE>
managing general partner for drilling and completing our wells an amount equal
to $39.15 per foot to the depth of the well at its deepest penetration,
proportionately reduced if we acquired less than 100% of the working interest in
a well. The total amount received by our managing general partner was
$11,988,350 for drilling and completing the wells. During 1999, we did not enter
into any further drilling transactions and none are anticipated.
PER WELL CHARGES. Our managing general partner, as operator, is
reimbursed at actual cost for all direct expenses incurred on our behalf and
receives well supervision fees for operating and maintaining the wells during
producing operations in the amount of $275 per well per month subject to an
annual adjustment for inflation. The well supervision fees are proportionately
reduced to the extent we acquired less than 100% of the working interest in a
well. During the calendar year ending December 31, 1999, our managing general
partner received $134,046 for well supervision fees.
As operator our managing general partner charges us at cost for third
party services and materials provided for each well which has been placed in
operation.
TRANSPORTATION AND MARKETING FEES. We pay a combined transportation and
marketing charge at a competitive rate, which is currently $0.29 for each mcf
transported, to the managing general partner and its affiliates, for natural gas
which we produce. See footnote 2 to the Organizational Diagram for a discussion
of the change of ownership of the gathering system. For the year ended December
31, 1999, we paid $192,016.
OTHER COMPENSATION. We will reimburse our managing general partner for
any loan it may make to us at a competitive rate of interest. If our managing
general partner provides equipment, supplies and other services to us it may do
so at competitive industry rates. For the calendar year ending December 31,
1999, our managing general partner did not advance any funds nor did it provide
any equipment, supplies or other services.
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
We have not filed any reports on Form 8-K during the last quarter of the
period covered by this report.
(a) Exhibits
See Exhibit Index on page 18.
17
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
DESCRIPTION LOCATION
----------- --------
<S> <C>
4(a) Certificate of Limited Partnership for Previously filed in the
Atlas-Energy for the Nineties-Public #7 Ltd. Form 10-KSB for the period
ending December 31, 1998
4(b) Amended and Restated Certificate and Agreement Previously filed in the
of Limited Partnership for Atlas-Energy for the Form 10-KSB for the period
Nineties-Public #7 Ltd. dated December 31, 1998 ending December 31, 1998
10(a) Drilling and Operating Agreement with exhibits Previously filed in the
Form 10-KSB for the period
ending December 31, 1998
</TABLE>
18
<PAGE>
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the
registrant caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
Atlas-Energy for the Nineties-Public #7 Ltd.
<TABLE>
<S> <C>
By: (Signature and Title): Atlas Resources, Inc., Managing General Partner
By (Signature and Title): /s/ Tony C. Banks
-----------------------------------------------------------------------------------
Tony C. Banks, President, Chief Executive Officer and a Director
</TABLE>
Date: April 14, 2000
In accordance with the Exchange Act, this report has been signed by the
following persons on behalf of the registrant and in the capacities and on the
dates indicated.
<TABLE>
<S> <C>
By (Signature and Title): /s/ Charles T. Koval
-----------------------------------------------------------------------------------
Charles T. Koval, Director
Date: April 14, 2000
By (Signature and Title): /s/ Tony C. Banks
-----------------------------------------------------------------------------------
Tony C. Banks, President, Chief Executive Officer and a Director
</TABLE>
Date: April 14, 2000
Supplemental information to be Furnished
With Reports Filed Pursuant to Section 15(d)
of the Exchange Act by Non-reporting Issuers
An annual report will be furnished to security holders subsequent to the filing
of this report.
19
<PAGE>
FINANCIAL STATEMENTS AND REPORT OF
INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
ATLAS-ENERGY FOR THE NINETIES - PUBLIC #7 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
December 31, 1999 and 1998
20
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Partners
ATLAS-ENERGY FOR THE NINETIES - PUBLIC #7 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
We have audited the accompanying balance sheets of Atlas-Energy for The
Nineties - Public #7 Ltd., A Pennsylvania Limited Partnership, as of December
31, 1999 and 1998, and the related statements of operations, changes in
partners' capital accounts and cash flows for the year ending December 31,
1999 and the period July 16, 1998 (date of formation) to December 31, 1998.
These financial statements are the responsibility of the Partnership's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Atlas-Energy for The Nineties
- -Public #7 Ltd. as of December 31, 1999 and the results of its operations,
changes in partners' capital accounts and cash flows for the year ending
December 31, 1999 and the period July 16, 1998 (date of formation) to December
31, 1998, in conformity with accounting principles generally accepted in the
United States.
/s/ Grant Thornton LLP
Cleveland, Ohio
March 1, 2000
21
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
BALANCE SHEETS
December 31
<TABLE>
<CAPTION>
ASSETS
1999 1998
------------- -------------
<S> <C> <C>
Cash $ 305,963 $ -
Accounts receivable - affiliate 360,833 -
Interest receivable - 29,592
Oil and gas wells and leases (Successful Efforts) 13,704,818 14,042,536
Less accumulated depletion and depreciation (8,320,672) -
------------- -------------
5,384,146 14,072,128
Organizational costs - 20,000
------------- -------------
$6,050,942 $14,092,128
============= =============
LIABILITIES AND PARTNERS' CAPITAL
Accounts payable - affiliate $ 19,601 $ -
Accrued liabilities 7,480 -
Partners' capital:
Managing General Partner (2,022,335) 2,074,186
Limited Partners (1,200 units) 8,046,196 12,017,942
------------- -------------
6,023,861 14,092,128
------------- -------------
$ 6,050,942 $14,092,128
============= =============
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
22
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
STATEMENTS OF OPERATIONS
For the periods ended December 31
<TABLE>
<CAPTION>
JULY 16, 1998
(DATE OF FORMATION)
TO DECEMBER 31,
1999 1998
------------ -------------------
<S> <C> <C>
Revenues
Natural gas sales $ 1,564,581 $ -
Interest income 8,065 29,592
------------ -------------------
1,572,646 29,592
Expenses
Well operating expense 126,004 -
Well supervision fees - affiliate 134,046 -
Depletion and depreciation of oil and gas
wells and leases 1,719,954 -
Impairment of oil and gas wells and leases 6,600,718 -
Professional and other expenses 9,706 -
General and administrative fees - affiliate 37,628 -
------------ -------------------
TOTAL EXPENSES 8,628,056 -
------------ -------------------
Earnings (loss) from continuing operations
before cumulative effect of a change in
accounting principle (7,055,410) 29,592
Cumulative effect of a change in accounting principle (20,000) -
------------ -------------------
NET (LOSS) EARNINGS $(7,075,410) $ 29,592
============ ===================
ALLOCATION OF NET (LOSS) EARNINGS:
Managing General Partner $(3,948,880) $ -
============ ===================
Limited Partners $(3,126,530) $ 29,592
============ ===================
Net (loss) earnings per limited partnership
interest $ (2,605.44) $ 24.66
============ ===================
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
23
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
STATEMENTS OF CHANGES IN
PARTNERS' CAPITAL ACCOUNTS
For the periods ended December 31, 1999 and 1998
<TABLE>
<CAPTION>
MANAGING
GENERAL LIMITED
PARTNER PARTNERS TOTAL
------------ ------------ --------------
<S> <C> <C> <C>
BALANCE AT JULY 16, 1998 $ - $ - $ -
Partners' Capital Contributions:
Cash - 11,988,350 11,988,350
Organizational and syndication costs 1,798,253 - 1,798,253
Tangible costs 1,845,386 - 1,845,386
Leasehold costs 208,800 - 208,800
------------ ------------ --------------
3,852,439 11,988,350 15,840,789
Syndication costs (1,778,253) - (1,778,253)
Participation in revenue and expenses:
Interest income - 29,592 29,592
------------ ------------ --------------
NET EARNINGS - 29,592 29,592
------------ ------------ --------------
BALANCE AT DECEMBER 31, 1998 2,074,186 12,017,942 14,092,128
Participation in revenue and expenses:
Net production revenues 404,405 900,126 1,304,531
Subordination of Managing General
Partner's income (77,568) 77,568 -
Interest income 2,500 5,565 8,065
Depletion and depreciation (877,177) (842,777) (1,719,954)
Impairment of oil and gas wells
and leases (3,366,366) (3,234,352) (6,600,718)
General and administrative (14,674) (32,660) (47,334)
Cumulative effect of a change in
accounting principle (20,000) - (20,000)
------------ ------------ --------------
NET LOSS (3,948,880) (3,126,530) (7,075,410)
Distributions (116,352) (538,787) (655,139)
Return of investors' capital - (267,382) (267,382)
Adjustments to assets contributed
by partners (31,289) (39,047) (70,336)
------------ ------------ --------------
BALANCE AT DECEMBER 31, 1999 $(2,022,335) $ 8,046,196 $ 6,023,861
============ ============ ==============
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
24
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
STATEMENTS OF CASH FLOWS
For the periods ended December 31
<TABLE>
<CAPTION>
JULY 16, 1998
(DATE OF FORMATION)
TO DECEMBER 31,
1999 1998
------------ -------------------
<S> <C> <C>
Cash flows from operating activities:
Net earnings (loss) $(7,075,410) $ 29,592
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 20,000 -
Depletion and depreciation 1,719,954 -
Impairment of oil and gas wells and leases 6,600,718
Increase in accounts receivable (360,833) -
Increase in accounts payable and accrued liabilities 27,081 -
Decrease (increase) in interest receivable 29,592 (29,592)
------------ -------------------
Net cash provided by operating activities 961,102 -
Cash flows from investing activities:
Payments for oil and gas well drilling contracts - (11,988,350)
Adjustment to oil and gas wells and leases 267,382 -
------------ -------------------
Net cash provided by investing activities 267,382 (11,988,350)
Cash flows from financing activities:
Partners' contributions - 11,988,350
Return of investors' capital (267,382) -
Capital distributions (655,139) -
------------ -------------------
Net cash (used in) provided by operating activities (922,521) 11,988,350
------------ -------------------
NET INCREASE IN CASH 305,963 -
Cash at beginning of year - -
------------ -------------------
Cash at end of year $ 305,963 $ -
============ ===================
SUPPLEMENTAL SCHEDULE OF NONCASH ACTIVITIES:
Assets contributed by Managing General Partner $ - $ 3,852,439
============ ===================
Adjustments to assets contributed by partners $ (70,336) $ -
============ ===================
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
25
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 1999 and 1998
A summary of significant accounting policies consistently applied in the
preparation of the accompanying financial statements follows:
1. NATURE OF OPERATIONS
Atlas-Energy for the Nineties - Public #7 Ltd. (the "Partnership") is a
Pennsylvania Limited Partnership which includes Atlas Resources, Inc.
("Atlas") of Pittsburgh, Pennsylvania, as Managing General Partner and
Operator, and 366 Limited Partners. The Partnership was formed on July 16,
1998 to drill and operate gas wells located primarily in Mercer County,
Pennsylvania. At December 31, 1999, the Partnership had various working
interests in 61 wells.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF ACCOUNTING
The financial statements are prepared in accordance with generally
accepted accounting principles.
Certain reclassifications have been made to the 1998 financial statements
to conform with the 1999 presentation.
OIL AND GAS WELLS AND LEASES
The Partnership uses the successful efforts method of accounting for oil
and gas producing activities. Costs to acquire mineral interests in oil
and gas properties and to drill and equip wells are capitalized.
Depreciation and depletion is computed on a field-by-field basis by the
unit-of-production method based on periodic estimates of oil and gas
reserves.
Undeveloped leaseholds and proved properties are assessed periodically or
whenever events or circumstances indicate that the carrying amount of
these assets may not be recoverable. Proved properties are assessed based
on estimates of future cash flows. As a result of this assessment, an
impairment loss of $6,600,718 was recognized in 1999.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements
and accompanying notes. Actual results could differ from those estimates.
26
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
NEW ACCOUNTING STANDARDS
In 1998, the AICPA issued Statement of Position 98-5 ("SOP 98-5"),
REPORTING ON THE COSTS OF START-UP ACTIVITIES. This statement requires
costs of start-up activities and organization costs, as defined, to be
expensed as incurred. The Partnership adopted the provisions of SOP 98-5
effective January 1, 1999 and, accordingly, wrote off the unamortized
organization costs of $20,000 as a charge to operations on January 1,
1999, which is reflected as a cumulative effect of a change in accounting
principle in the 1999 Statement of Operations.
3. FEDERAL INCOME TAXES
The Partnership is not treated as a taxable entity for federal income tax
purposes. Any item of income, gain, loss, deduction or credit flows
through to the partners as though each partner had incurred such item
directly. As a result, each partner must take into account his pro rata
share of all items of partnership income and deductions in computing his
federal income tax liability.
4. PARTICIPATION IN REVENUES AND COSTS
Atlas and the other partners generally participate in revenues and costs
in the following manner:
<TABLE>
<CAPTION>
SUBSCRIBING
ATLAS PARTNERS
----- -----------
<S> <C> <C>
Organization and offering costs 100% 0%
Lease costs 100% 0%
Revenues 31% 69%
Direct operating costs 31% 69%
Intangible drilling costs 0% 100%
Tangible costs 51% 49%
Tax deductions:
Intangible drilling and development costs 0% 100%
Depreciation 51% 49%
Depletion allowances 31% 69%
</TABLE>
27
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
5. TRANSACTIONS WITH ATLAS AND ITS AFFILIATES
The Partnership has entered into the following significant transactions
with Atlas and its affiliates as provided under the Partnership agreement:
Drilling contracts to drill and complete Partnership wells at a cost
of $39.15 per foot on completed wells. Drilling costs of $11,988,350
were paid in 1998, of which $267,382 was refunded in 1999.
Administrative costs at $75 per well per month. Administrative costs
incurred in 1999 were $37,628. No administrative costs were incurred
in 1998.
Well supervision fees initially of $275 per well per month plus the
cost of third party materials and services. Well supervision fees
incurred in 1999 were $134,046. No well supervision fees were
incurred in 1998.
Reimbursement of gas transportation and marketing charges.
6. PURCHASE COMMITMENT
Subject to certain conditions, investor partners may present their
interests beginning in 2003 for purchase by Atlas. Atlas is not obligated
to purchase more than 5% of the units in any calendar year.
7. SUBORDINATION OF MANAGING GENERAL PARTNER'S REVENUE SHARE
Atlas will subordinate a part of its partnership revenues in an amount up
to 12.4% of production revenues of the Partnership, net of related
operating costs, administrative costs and well supervision fees to the
receipt by participants of cash distributions from the Partnership equal
to at least 10% of their agreed subscriptions of $11,988,350, determined
on a cumulative basis, in each of the first five years of Partnership
operations, commencing with the first distribution of revenues to the
participants.
Net production revenues distributed to participants in 1999 for the
subordination year ending December 1999 amounted to $538,787 including the
subordination of $77,568 of Atlas revenues. At December 31, 1999, the
balance of net revenues subordinated by Atlas was $77,568.
28
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
8. INDEMNIFICATION
In order to limit the potential liability of the investor general
partners, Atlas and Atlas America, Inc., formerly The Atlas Group, Inc.
(parent company of Atlas) has agreed to indemnify each investor general
partner from any liability incurred which exceeds such partner's share of
Partnership assets.
9. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
The supplementary information summarized below presents the results of
natural gas and oil activities in accordance with SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities".
No consideration has been given in the following information to the income
tax effect of the activities as the Partnership is not treated as a
taxableentity for income tax purposes.
(1) CAPITALIZED COSTS
The following table presents the capitalized costs related to natural gas
and oil product activities:
<TABLE>
<CAPTION>
---------------------------------
1999 1998
---------------------------------
<S> <C> <C>
Capitalized costs at December 31:
Proved properties $13,704,818 $14,042,536
Accumulated depreciation and depletion (8,320,672) -
---------------------------------
NET CAPITALIZED COSTS $5,384,146 $14,042,536
=================================
Costs incurred during the year:
Development costs $(337,718) $14,042,536
=================================
</TABLE>
Development costs include costs to gain access to and prepare development
well locations for drilling, to drill and equip development wells and to
provide facilities to extract, treat, gather and store oil and gas. The
credit of $337,718 for 1999 represents an adjustment to oil and gas wells
and leases in connection with unused funds from drilling contracts that
were refunded to the investors.
29
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
9. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
(2) RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
The following table presents the results of operations related to natural
gas and oil production for the year ended December 31, 1999:
<TABLE>
<S> <C>
Natural gas sales $ 1,564,581
Production costs (260,050)
Depreciation, depletion and impairment (8,320,672)
------------
Results of operations from producing
activities $(7,016,141)
============
</TABLE>
Depreciation and depletion of natural gas and oil properties are expensed
at unit cost rates calculated annually based on the estimated volume of
recoverable gas and the related costs.
(3) RESERVE INFORMATION
The information presented below represents estimates of proved natural gas
and oil reserves. Reserves are estimated in accordance with guidelines
established by the Securities and Exchange Commission and the Financial
Accounting Standards Board which require that reserve estimates be
prepared under existing economic and operating conditions with no
provision for price and cost escalation except by contractual
arrangements. Proved reserves are estimated quantities of oil and natural
gas which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs. Proved
developed reserves and are those which are expected to be recovered
through existing wells with existing equipment and operating methods. All
reserves are proved developed reserves and are located in the Appalachian
Basin area.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates
only and should not be construed as being exact. In addition, the
standardized measures of discounted future net cash flows may not
represent the fair market value of the Company's oil and gas reserves or
the present value of future cash flows of equivalent reserves, due to
anticipated future changes in oil and gas prices and in production and
development costs and other factors for which effects have not been
provided.
30
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
9. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
(3) RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES - CONT'D
<TABLE>
<CAPTION>
=============
1999
-------------
NATURAL GAS
(MCF)
-------------
<S> <C>
Proved developed reserves:
Beginning of period -
Production (662,125)
Current additions 5,273,974
-------------
END OF PERIOD 4,611,849
=============
</TABLE>
(4) STANDARD MEASURE OF DISCOUNTED FUTURE CASH FLOWS
The standardized measure of discounted future net cash flows is
information provided for the financial statement user as a common base
for comparing oil and gas reserves of enterprises in the industry. The
following schedule presents the standardized measure of estimated
discounted future net cash flows from the Company's proved reserves.
Estimated future cash flows are determined by using the weighted average
price received for the month of December 1999 adjusted only for fixed and
determinable increases in natural gas prices provided by contractual
agreements. The standardized measure of future net cash flows was
prepared using the prevailing economic conditions existing at December
31, 1999 and such conditions continually change. Accordingly, such
information should not serve as a basis in making any judgment on the
potential value of recoverable reserves or in estimating future results
of operations.
<TABLE>
<CAPTION>
=============
1999
-------------
<S> <C>
Future cash inflows $13,227,312
Future production costs (7,150,155)
-------------
FUTURE NET CASH FLOW 6,077,157
10%annual discount for estimated
timing of cash flows (2,082,176)
-------------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS $3,994,981
=============
</TABLE>
31
<PAGE>
Atlas-Energy for the Nineties - Public #7 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
9. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
Summary of changes in the standardized measure of discounted future net
cash flows:
<TABLE>
<CAPTION>
=============
1999
-------------
<S> <C>
BALANCE, BEGINNING OF PERIOD $ -
Sales of gas and oil produced - net of
related costs (1,304,531)
Net changes in prices, production and
development costs -
Discoveries and extensions 5,299,512
Accretion of discount -
------------
BALANCE, END OF PERIOD $ 3,994,981
============
</TABLE>
32
