<PAGE>
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 333-31681
Atlas-Energy for the Nineties-Public #6 Ltd.
(Name of small business issuer in its charter)
Pennsylvania 23-2888337
(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. $1,376,357
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 X No
--- ---
<PAGE>
PART I
ITEM 1. DESCRIPTION OF BUSINESS ATLAS-ENERGY FOR THE NINETIES-PUBLIC #6 LTD.
(THE "PARTNERSHIP")
We were formed under the Pennsylvania Revised Uniform Limited Partnership
Act on July 1, 1997, 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 3, "Directors,
Executive Officers and Significant Employees."
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, 1997. Our
final closing date was December 31, 1997, and we were funded with total
subscriptions of $9,901,025.
A total of 44.45 net wells were drilled to the Clinton/Medina
geological formation in Mercer and Lawrence Counties, Pennsylvania. 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 time 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 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 which imposes 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;
- landowner notification requirements;
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- 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.
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 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
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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 44.45 net wells and all wells were
productive. The wells were drilled and completed by June 29, 1998. 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,
----------------------------------------------------------------
1997 1998 1999
---- ---- ----
Gross Net Gross Net Gross Net
----- --- ----- ----- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development Wells:
Oil..................................... 0 0 0 0 0 0
Gas..................................... 0 0 55 44.45 0 0
Dry..................................... 0 0 0 0 0 0
----- --- ----- ----- ----- ---
Total............................... 0 0 55 44.45 0 0
===== === ===== ===== ===== ===
</TABLE>
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.
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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,
---------------------------------------------------
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
Production (1):
Oil (Bbls).................................... 0 0 25
Natural Gas (Mcf)............................. 0 816,375 646,219
Total (Equivalent Barrels) (2)............... 0 136,063 107,728
Average Sales Price:
Per Equivalent Barrel (2)(3).................. 0 $12.66 $12.69
Average Production Cost (lifting cost):
Per Equivalent Barrel (2)(4).................. 0 $ 1.60 $ .82
</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 are subject to a
12.5% landowner's royalty and have an 87.5% 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 $2.22 in
1998, and $2.27 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................... 55 44.45
----- -----
Total..................... 55 44.45
===== =====
</TABLE>
"Productive wells" are producing wells and wells capable of production.
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.
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<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 4,094,324 682,387 $3,589
------- --------- ------- ------
Proved Undeveloped.................. 0 0 0 0
------- --------- ------- ------
0 4,094,324 682,387 $3,589
Total ======= ========= ======= ======
</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.
"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.
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- 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
- 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
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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................. 2,512 2,025 0 0 2,512 2,025
----- ----- ------- ------ ----- -----
Total ............ 2,512 2,025 0 0 2,512 2,025
===== ===== ======= ====== ===== =====
</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 in 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 indexes 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 partner 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. DIRECTORS, EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES
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.
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.
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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.
<TABLE>
<CAPTION>
ORGANIZATIONAL DIAGRAM (1)(2)
-------------------------------------
Resource America, Inc.
-------------------------------------
-------------------------------------
Atlas America, Inc.
-------------------------------------
-------------------------------------
AIC, Inc.
-------------------------------------
---------------------- ------------------ -------------------- -------------------- -----------------------
<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 the 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.
DIRECTORS, EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES OF ATLAS. The
executive officers, directors and significant employees of our managing general
partner are as follows:
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<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.
12
<PAGE>
ITEM 4. REMUNERATION OF DIRECTORS AND OFFICERS
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 6, "Interest of Management and Others in Certain
Transactions," below for compensation which we paid to our managing general
partner.
ITEM 5. SECURITY OWNERSHIP OF MANAGEMENT AND CERTAIN SECURITY HOLDERS
As of December 31, 1999, we had issued and outstanding 991.615 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 6. INTEREST OF MANAGEMENT AND OTHERS IN CERTAIN TRANSACTIONS
OIL AND GAS REVENUES. Our managing general partner is allocated 25% of
our oil and gas revenues in return for having paid organization and offering
costs equal to 15% of our subscriptions, 14% of tangible costs and
contributing all leases for a total capital contribution of $1,968,637.
During the calendar year ending December 31, 1999, our managing general
partner received $319,720 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) 55 undeveloped prospects
to drill approximately 44.45 net wells. Our managing general partner received
a credit in the amount of $156,420 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 $40,106 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 $44,558
as reimbursement for direct costs.
DRILLING CONTRACTS. On December 1, 1997, as amended on December 31,
1997, we entered into a drilling contract with our managing general partner
to drill and complete 44.45 net wells. We paid the managing general partner
for drilling and completing our wells an amount equal to $37.39 per foot to
the depth of the well at its deepest penetration, proportionately reduced if
we acquired less than 100% of the
13
<PAGE>
working interest in a well. The total amount received by our managing general
partner was $10,228,088 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 $43,557 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 $187,404.
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.
PART II
ITEM 7. 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 that 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:
- 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.
14
<PAGE>
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 393 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 funds 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
$1,032,437 to you and the other participants and $344,145 to our managing
general partner.
ITEM 8. LEGAL PROCEEDINGS
None.
ITEM 9. 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 1, 1997, 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
15
<PAGE>
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 reports of the former principal accountants on our financial
statements since our formation contained no adverse opinion or disclaimer of
opinion, nor were they qualified or modified as to uncertainty, audit scope,
or accounting principles.
ITEM 10. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
ITEM 11. COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
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.
ITEM 12. 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.
PART F/S
ITEM 13. FINANCIAL STATEMENTS
Our Financial Statements for the last fiscal year, together with the
opinion of the accountants thereon, are on pages 19 through 30 of this report.
PART III
ITEM 14. EXHIBITS
(a) Exhibits See Exhibit Index on page 17.
16
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
DESCRIPTION LOCATION
----------- --------
<S> <C> <C>
4(a) Certificate of Limited Partnership for Previously filed in the
Atlas-Energy for the Nineties-Public #6 Ltd. Form 10-KSB for the period
ending December 31, 1997.
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 #6 Ltd. dated December 31, 1997 ending December 31, 1997.
10(a) Drilling and Operating Agreement with exhibits Previously filed in the
Form 10-KSB for the period
ending December 31, 1997.
</TABLE>
17
<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.
<TABLE>
<CAPTION>
Atlas-Energy for the Nineties-Public #6 Ltd.
<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
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.
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
Date: April 14, 2000
</TABLE>
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.
18
<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
19
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Partners
ATLAS-ENERGY FOR THE NINETIES - PUBLIC #6 LTD.
A PENNSYLVANIA LIMITED PARTNERSHIP
We have audited the accompanying balance sheets of Atlas-Energy for The
Nineties - Public #6 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 years then ended. 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 #6 Ltd. as of December 31, 1999 and 1998 and the results of its
operations, changes in partners' capital accounts and cash flows for the years
then ended, in conformity with accounting principles generally accepted in the
United States.
/s/ Grant Thornton LLP
Cleveland, Ohio
March 1, 2000
20
<PAGE>
Atlas-Energy for the Nineties - Public #6 Ltd.
(A Pennsylvania Limited Partnership)
BALANCE SHEETS
December 31
<TABLE>
<CAPTION>
ASSETS
1999 1998
----------- -----------
<S> <C> <C>
Cash $ 14,662 $ 7,960
Accounts receivable - affiliate 298,026 444,226
Oil and gas wells and leases (Successful Efforts) 10,355,660 10,355,660
Less accumulated depletion and depreciation (2,372,975) (1,113,233)
----------- -----------
7,982,685 9,242,427
----------- -----------
$8,295,373 $9,694,613
=========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Accounts payable - affiliate $ 9,878 $ 11,014
Accrued liabilities 4,897 6,711
Partners' capital:
Managing General Partner 331,143 541,645
Limited Partners (991.615 units) 7,949,455 9,135,243
----------- -----------
8,280,598 9,676,888
----------- -----------
$8,295,373 $9,694,613
=========== ===========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
21
<PAGE>
Atlas-Energy for the Nineties - Public #6 Ltd.
(A Pennsylvania Limited Partnership)
STATEMENTS OF OPERATIONS
For the years ended December 31
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
Revenues
Natural gas sales $1,366,996 $1,721,899
Interest income 9,361 4,530
----------- -----------
1,376,357 1,726,429
Expenses
Well operating expense 44,558 109,396
Well supervision fees - affiliate 43,557 107,823
Depletion and depreciation of oil and gas
wells and leases 1,259,742 1,272,886
General and administrative fees - affiliate 40,106 33,587
Professional and other expenses 8,102 10,232
----------- -----------
TOTAL EXPENSES 1,396,065 1,533,924
----------- -----------
NET (LOSS) EARNINGS $ (19,708) $ 192,505
=========== ===========
Allocation of net (loss) earnings:
- ----------------------------------
Managing General Partner $ 133,643 $ 171,181
=========== ===========
Limited partners $ (153,351) $ 21,324
=========== ===========
Net (loss) earnings per limited partnership
interest ($154.65) $21.50
=========== ===========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
22
<PAGE>
Atlas-Energy for the Nineties - Public #6 Ltd.
(A Pennsylvania Limited Partnership)
STATEMENTS OF CHANGES IN PARTNERS' CAPITAL ACCOUNTS
For the years ended December 31, 1999 and 1998
<TABLE>
<CAPTION>
MANAGING
GENERAL LIMITED
PARTNER PARTNERS TOTAL
----------- ----------- ------------
<S> <C> <C> <C>
BALANCE AT DECEMBER 31, 1997 $ 643,136 $9,923,560 $10,566,696
Participation in revenue and expenses:
Net production revenues 376,170 1,128,510 1,504,680
Interest income 1,132 3,398 4,530
Depletion and depreciation (195,166) 1,077,720) (1,272,886)
General and administrative (10,955) (32,864) (43,819)
----------- ----------- ------------
NET EARNINGS 171,181 21,324 192,505
Adjustments to assets contributed
by partners (14,940) (3,352) (18,292)
Distributions (257,732) (806,289) (1,064,021)
----------- ----------- ------------
BALANCE AT DECEMBER 31, 1998 541,645 9,135,243 9,676,888
Participation in revenue and expenses:
Net production revenues 319,720 959,161 1,278,881
Interest income 2,340 7,021 9,361
Depletion and depreciation (176,364) (1,083,378) (1,259,742)
General and administrative (12,053) (36,155) (48,208)
----------- ----------- ------------
NET EARNINGS (LOSS) 133,643 (153,351) (19,708)
Distributions (344,145) (1,032,437) (1,376,582)
------------ ----------- ------------
BALANCE AT DECEMBER 31, 1999 $ 331,143 $7,949,455 $ 8,280,598
=========== =========== ============
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
23
<PAGE>
Atlas-Energy for the Nineties - Public #6 Ltd.
(A Pennsylvania Limited Partnership)
STATEMENTS OF CASH FLOWS
For the years ended December 31
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
Cash flows from operating activities:
Net (loss) earnings $ (19,708) $ 192,505
Adjustments to reconcile net (loss) earnings to net cash
provided by operating activities:
Depletion and depreciation 1,259,742 1,272,886
Adjustment to oil and gas wells and leases - 10,556
Decrease (increase) in accounts receivable 146,200 (426,150)
Decrease in advance from Managing General Partner - (15,000)
(Decrease) increase in accounts payable and
accrued liabilities (2,950) 17,725
----------- -----------
Net cash provided by operating activities 1,383,284 1,052,522
Cash flows from financing activities:
Capital distributions (1,376,582) (1,064,021)
----------- -----------
NET INCREASE (DECREASE) IN CASH 6,702 (11,499)
Cash at beginning of year 7,960 19,459
----------- -----------
Cash at end of year $ 14,662 $ 7,960
=========== ===========
SUPPLEMENTAL SCHEDULE OF NONCASH ACTIVITIES:
Adjustments to assets contributed by partners $ - $ (18,292)
=========== ===========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
24
<PAGE>
Atlas-Energy for the Nineties - Public #6 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 #6 Ltd. (the "Partnership") is a
Pennsylvania Limited Partnership which includes Atlas Resources, Inc.
("Atlas") of Pittsburgh, Pennsylvania, as Managing General Partner and
Operator, and 393 Limited Partners. The Partnership was formed on July 1,
1997 to drill and operate gas wells located primarily in Mercer County,
Pennsylvania. At December 31, 1999, the Partnership had various working
interests in 55 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.
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.
25
<PAGE>
Atlas-Energy for the Nineties - Public #6 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 organization costs are expensed
as incurred.
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 25% 75%
Direct operating costs 25% 75%
Intangible drilling costs 0% 100%
Tangible costs 14% 86%
Tax deductions:
Intangible drilling and development costs 0% 100%
Depreciation 14% 86%
Depletion allowances 25% 75%
</TABLE>
26
<PAGE>
Atlas-Energy for the Nineties - Public #6 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 $37.39 per foot on completed wells. No drilling costs were
incurred in 1999 and 1998.
Administrative costs at $75 per well per month. Administrative costs
incurred in 1999 and 1998 were $40,106 and $33,587, respectively.
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 and 1998 were $43,557 and $107,823, respectively.
Reimbursement of gas transportation and marketing charges.
6. PURCHASE COMMITMENT
Subject to certain conditions, investor partners may present their
interests beginning in 2001 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 10% 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 $9,901,025, 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.
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) have agreed to indemnify each investor general
partner from any liability incurred which exceeds such partner's share of
Partnership assets.
27
<PAGE>
Atlas-Energy for the Nineties - Public #6 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
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
taxable entity 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 $ 10,355,660 $ 10,355,660
Accumulated depreciation and depletion (2,372,975) (1,113,233)
--------------------------------------
NET CAPITALIZED COSTS $ 7,982,685 $ 9,242,427
======================================
</TABLE>
(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 years ended December 31, 1999 and 1998:
<TABLE>
<CAPTION>
1999 1998
--------------------------------------
<S> <C> <C>
Natural gas sales $ 1,366,996 $ 1,721,899
Production costs (88,115) (217,219)
Depreciation and depletion (1,259,742) (1,113,233)
--------------------------------------
Results of operations from producing
activities $ 19,139 $ 391,447
======================================
</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.
28
<PAGE>
Atlas-Energy for the Nineties - Public #6 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) 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 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
standarized 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.
<TABLE>
<CAPTION>
1999 1998
NATURAL GAS NATURAL GAS
(MCF) (MCF)
----------------------------------------
<S> <C> <C>
Proved developed reserves:
Beginning of period 5,631,068 -
Production (646,219) (816,375)
Current additions - 6,447,443
Revisions to previous estimates (890,525) -
----------------------------------------
END OF PERIOD 4,094,324 5,631,068
========================================
</TABLE>
29
<PAGE>
Atlas-Energy for the Nineties - Public #6 Ltd.
(A Pennsylvania Limited Partnership)
NOTES TO FINANCIAL STATEMENTS - CONTINUED
December 31, 1999 and 1998
9. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)
(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 judgement on the
potential value of recoverable reserves or in estimating future results
of operations.
<TABLE>
<CAPTION>
1999 1998
-------------------------------------------
<S> <C> <C>
Future cash inflows $ 11,605,979 $13,137,280
Future production costs (5,506,597) (5,485,285)
Future net cash flow 6,099,382 7,651,995
10% annual discount for estimated
timing of cash flows (2,509,973) (3,166,039)
-------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS $ 3,589,409 $ 4,485,956
===========================================
</TABLE>
Summary of changes in the standardized measure of discounted future net
cash flows:
<TABLE>
<CAPTION>
1999 1998
-------------------------------------------
<S> <C> <C>
BALANCE, BEGINNING OF PERIOD $ 4,485,956 $ -
Sales of gas and oil produced -
net of related costs (1,278,881) (1,504,680)
Net changes in prices and
production costs (66,262) -
Discoveries and extensions - 5,990,636
Accretion of discount 448,596 -
-------------------------------------------
BALANCE, END OF PERIOD $ 3,589,409 $ 4,485,956
===========================================
</TABLE>
30
