As filed with the Securities and Exchange Commission on July 13, 2005
File No. 0-51272
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
AMENDMENT NO. 2 TO
FORM 10
GENERAL FORM FOR REGISTRATION OF SECURITIES
PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
ATLAS AMERICA SERIES 25-2004(B) L.P.
(Exact Name of registrant as specified in its charter)
DELAWARE 34-1980376
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
311 ROUSER ROAD
MOON TOWNSHIP, PENNSYLVANIA 15108
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(412) 262-2830
Securities to be registered pursuant to Section 12(b) of the Act:
NONE
Securities to be registered pursuant to Section 12(g) of the Act:
UNITS (1)
(Title of Class)
- ----------
(1) Units means limited partner units and investor general partner units,
which will be automatically converted into limited partner units once
our wells are drilled and completed.
TABLE OF CONTENTS
PAGES
Item 1 Business .......................................................................................... 1 - 18
Item 2 Financial Information..............................................................................18 - 23
Item 3 Properties.........................................................................................23 - 27
Item 4 Security Ownership of Certain Beneficial Owners and Management..........................................28
Item 5 Directors and Executive Officers.................................................................. 29 - 36
Item 6 Executive Compensation..................................................................................36
Item 7 Certain Relationships and Related Transactions.....................................................36 - 37
Item 8 Legal Proceedings......................................................................................37
Item 9 Market Price of and Dividends on the Registrant's Common Equity and Related
Stockholder Matters.....................................................................................38
Item 10 Recent Sales of Unregistered Securities.................................................................39
Item 11 Description of Registrant's Securities to be Registered............................................39 - 47
Item 12 Indemnification of Directors and Officers..........................................................47 - 48
Item 13 Financial Statements and Supplementary Data.............................................................48
Item 14 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................48
Item 15 Financial Statements and Exhibits..................................................................49 - 62
ITEM 1. BUSINESS.
THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING EVENTS
AND FINANCIAL TRENDS WHICH MAY AFFECT OUR FUTURE OPERATING RESULTS AND FINANCIAL
POSITION. SUCH STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT COULD
CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM THOSE
ANTICIPATED IN SUCH STATEMENTS. THESE RISKS INCLUDE RISKS ASSOCIATED WITH
DEVELOPING, OPERATING AND MARKETING NATURAL GAS AND OIL WELLS, AND FLUCTUATIONS
IN THE MARKET PRICES FOR NATURAL GAS AND OIL. FOR A MORE COMPLETE DISCUSSION OF
THE RISKS AND UNCERTAINTIES TO WHICH WE ARE SUBJECT, SEE "RISK FACTORS" IN THIS
ITEM 1. THE TERMS "WE", "OUR", "US", "ITS" AND THE "COMPANY" USED IN THIS FORM
10 ARE USED AS REFERENCES TO ATLAS AMERICA SERIES 25-2004 (B) L.P.
GENERAL
We were formed as a Delaware limited partnership on January 21, 2004, with Atlas
Resources, Inc. as our managing general partner. Partnership operations began at
our first closing on June 21, 2004. When we had our final closing on August 31,
2004 we had 634 investors who purchased Units (the "participants"). Units mean
our limited partner units and investor general partner units, which will be
automatically converted into limited partner units once our wells are drilled
and completed. In accordance with the terms of the offering, 1,218.46 Units were
sold at $25,000 per Unit, 39.92 Units were sold at $23,000 per Unit to selling
agents and their registered representatives and principals and a client of a
registered investment advisor, and 7 Units were sold at $21,625 per Unit to the
managing general partner, its officers, directors and affiliates, and investors
who bought Units through the officers and directors of the managing general
partner.
The participants contributed $31,531,000 in subscription proceeds which were
paid to our managing general partner as operator and general drilling contractor
under our drilling and operating agreement. We used all of our subscription
proceeds to drill and operate wells located primarily in western Pennsylvania
and central Tennessee as described below. Under the partnership agreement, all
of the subscription proceeds of our participants were used to pay the intangible
drilling costs of our wells and a portion of the tangible costs. Intangible
drilling costs generally means those costs of drilling and completing a well
that are currently deductible, as compared with lease costs, which must be
recovered through the depletion allowance, and equipment costs, which must be
recovered through depreciation deductions. Tangible costs generally means the
equipment costs of drilling and completing a well that are not currently
deductible as intangible drilling costs and are not lease costs. Our managing
general partner was required to contribute leases on which our wells are
situated, pay and/or contribute services towards organization and offering costs
up to an amount equal to 15% of the participants' subscription proceeds and pay
the majority of our equipment costs to drill and complete our wells. As of
December 31, 2004 the aggregate amount of these contributions by our managing
general partner was $16,007,100.
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Our investment objectives are to:
o Provide monthly cash distributions from the wells drilled with our
subscription proceeds until the wells are depleted, with minimum annual
aggregate cash distributions per unit to our participants equal to at least
$2,500 (which is 10% of $25,000 per Unit, regardless of the actual
subscription price paid) during the first five years beginning with our
first distribution of revenues to our participants. These distributions
during the first five years are not guaranteed, but are subject to our
managing general partner's subordination obligation as described in Item 11
"Description of Registrant's Securities to be Registered - Distributions."
Under current conditions, and based in part on the drilling results of our
47 net initial wells (31% of our total estimated net wells) which were
drilled and completed in 2004, we believe that our participants will
receive these minimum aggregate distributions of $2,500 per Unit per year
during this five year period. See Item 3. "Properties" and Note 9 of the
"Notes to Financial Statements" in Item 13 "Financial Statements and
Supplementary Data." However, we do not yet know the drilling results of
all of the approximately 106.40 net wells (69% of our total estimated net
wells) which we prepaid in 2004 and are currently in the process of
drilling and completing as described more fully in Item 3 "Properties."
Therefore, a participant should not place too much reliance on the results
of the initial wells we drilled and completed in 2004, since we expect that
those wells will comprise only approximately 31% of our estimated total net
wells once we have completed our drilling activities. Also, current
conditions, such as prices for natural gas and our costs for operating our
wells, will change during the next five years. See "Risk Factors - Risks
Relating to Our Business," below.
o Obtain federal income tax deductions in 2004 from intangible drilling costs
in an amount to equal not less than 90% of each participant's subscription
price for his or her Units. These deductions for intangible drilling costs
may be used to offset a portion of the participant's taxable income,
subject to any objections by the IRS, each participant's individual tax
circumstances, and the passive activity rules if the participant invested
as a limited partner. For example, if a participant paid $25,000 for a Unit
the investment would produce a 2004 tax deduction of not less than $22,500
per unit, 90%, against:
o ordinary income, or capital gain in some situations, if the
participant invested as an investor general partner; and
o passive income if the participant invested as a limited partner.
In the first quarter of 2005, our IRS Schedule K-1's to our participants
reported a deduction for intangible drilling costs in 2004 in an amount
equal to 90% of the subscription price paid by each participant. However,
we do not guarantee the IRS treatment of our participants' deductions for
intangible drilling costs. If the IRS were to decrease the amount of the
deduction, or defer part of the deduction to 2005 for wells we prepaid in
2004, for example, our participants would not be entitled to any
reimbursement from us for any increase in taxes owed, penalties or interest
or any other lost tax benefits.
2
o Offset a portion of any gross production income generated by us with
tax deductions from percentage depletion.
o Provide each of our participants with tax deductions, in an aggregate
amount guaranteed to equal the remaining 10% of the participant's
initial investment, through annual depreciation deductions over a
seven-year cost recovery period. The tax benefits of these
depreciation deductions to our participants are subject to any
objections by the IRS, each participant's individual tax
circumstances, and the passive activity rules if the participant
invested as a limited partner. Also, we do not guarantee the IRS
treatment of our participants' depreciation deductions for our
equipment costs. If the IRS were to decrease the amount of the
deductions, for example, our participants would not entitled to any
reimbursement from us for any increase in taxes owed, penalties or
interest or any other lost tax benefits.
We are filing this General Form for Registration of Securities on Form 10 to
register our Units pursuant to Section 12(g) of the Securities Exchange Act of
1934, as amended (the "Exchange Act"). We are subject to the registration
requirements of Section 12(g) because at the end of our first fiscal year on
December 31, 2004, the aggregate value of our assets exceeded the applicable
threshold of $10 million and our Units of record were held by more than 500
persons. Because of our obligation to register our Units with the Securities and
Exchange Commission (the "SEC") under the Exchange Act, we will be subject to
the requirements of the Exchange Act rules. In particular, we will be required
to file quarterly reports on Form 10-Q, annual reports on Form 10-K, and current
reports on Form 8-K and otherwise comply with the disclosure obligations of the
Exchange Act applicable to issuers filing registration statements pursuant to
Section 12(g) of the Exchange Act.
OIL AND NATURAL GAS PROPERTIES. We have drilled and completed 51 net development
wells and are in the process of drilling approximately 106.40 additional net
development wells which were prepaid in 2004, but were spudded in the first
quarter of 2005. Because all of our wells have not been drilled and completed,
our investor general partner units have not been converted to limited partner
units. We will not drill any wells except the wells funded with our initial
subscription proceeds and our managing general partner's contribution as
described above. For further information concerning our natural gas and oil
properties, including the number of wells in which we have a working interest,
and our reserve and acreage information, see Item 3 "Properties."
We believe that our ongoing operating and maintenance costs for our productive
wells will be paid through revenues we receive from the sale of our natural gas
and oil production as discussed in Item 2 "Financial Information." Thus, the
subscription proceeds from the offering of our Units in 2004 and our ongoing
natural gas and oil production revenues from our wells will satisfy all of our
cash requirements and we will not seek to raise additional funds from investors.
We pay our managing general partner a monthly well supervision fee of $275 per
well, as outlined in our drilling and operating agreement, for serving as the
operator of our wells. This well supervision fee covers all normal and regularly
recurring operating expenses for the production and sale of natural gas and to a
lesser extent oil, such as well tending, routine maintenance and adjustment,
reading meters, recording production, pumping, maintaining appropriate books and
records and preparing reports to us and to government agencies. The well
supervision fees, however, do not include costs and expenses related to the
purchase of certain equipment, materials and brine disposal. If these expenses
are incurred, we will pay these expenses at the invoice cost for third-party
services and materials and we will pay a reasonable charge for services
performed directly by our managing general partner or its affiliates.
3
PRODUCTION. All of our wells will produce, and some of our wells are currently
producing, natural gas and to a far lesser extent oil, which are our only
products. We do not plan to sell any of our wells and will continue to produce
them until they are depleted at which time they will be plugged and abandoned.
No other wells will be drilled beyond those drilled with the subscription
proceeds and our managing general partner's contribution as described above. For
information concerning our natural gas and oil production quantities, average
sales prices and average production costs, see Item 3 "Properties."
SALE OF NATURAL GAS AND OIL PRODUCTION. Our managing general partner is
responsible for selling our natural gas and oil production. In the geographic
areas where our wells are situated, our managing general partner is a party to
natural gas contracts with various natural gas purchasers, each of which is
paying a different price for our natural gas. To reduce the conflict of interest
among us and our managing general partner's other partnerships concerning to
whom and at what price our natural gas and oil will be sold, our managing
general partner's policy is to treat all wells in any given geographic area
equally by calculating a weighted average selling price for all of the natural
gas sold in the geographic area. This is the price we and the other partnerships
receive for our respective natural gas production in that geographic area.
Our managing general partner is responsible for gathering and transporting the
natural gas produced by us to interstate pipeline systems, local distribution
companies, and/or end-users in the area. We will pay our managing general
partner a competitive gathering fee for this service which our managing general
partner anticipates will range from $.29 per mcf to $.35 per mcf (an mcf means
1,000 cubic feet of natural gas), except in the Armstrong County area where our
managing general partner anticipates the gathering fee, if any, will be $.20 per
mcf, the McKean County area where the gathering fee is $.70 per mcf and central
Tennessee where the gathering fee is $.55 per mcf transportation plus actual
costs for compression. For the majority of our natural gas production, our
managing general partner will use the gathering system owned by Atlas Pipeline
Partners, L.P., which is a master limited partnership operated by Atlas America,
the indirect parent company of our managing general partner. Although Atlas
America is required to pay a gathering fee to Atlas Pipeline Partners equal to
the greater of $0.35 per mcf or 16% of the gross sales price for each mcf
transported through the gathering system of Atlas Pipeline Partners, we will pay
a lesser amount, and Atlas America must pay the difference to Atlas Pipeline
Partners. If our natural gas is not transported through the Atlas Pipeline
Partners gathering system, it is because there is a third-party operator of our
wells or the gathering system has not been extended to our wells. In these
cases, our natural gas will be transported through a third-party gathering
system, and we will pay our managing general partner a competitive gathering
fee, all or a portion of which will be paid by it to the third-party which
transports our natural gas.
Initially, the majority of our natural gas production will be sold to UGI Energy
Services, Inc. since the majority of our wells have been or will be drilled in
Fayette County, Pennsylvania, and the majority of our natural gas production
from Fayette County will be sold to UGI Energy Services until March 31, 2007. In
this regard, UGI Corporation has provided a $7 million guaranty of the payment
obligations of UGI Energy Services, Inc. until March 31, 2007, subject to
4
termination of the guarantee by UGI Corporation on 45 days prior written notice.
Also, our natural gas production from Armstrong County will be sold to U.S.
Energy Exploration Corporation, our natural gas production from McKean County
will be sold to M&M Royalty Ltd. and our natural gas production from Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee will be sold to Duke
Energy. Our managing general partner anticipates that the remainder of our
natural gas will be sold to Amerada Hess Corporation pursuant to a natural gas
supply agreement which was first entered into with First Energy Solutions
Corporation for a 10-year term which began on April 1, 1999, but is now
effectively an agreement with Amerada Hess Corporation since First Energy
Solutions Corporation has now been acquired by Amerada Hess Corporation. Under
this agreement, Amerada Hess Corporation is to buy all of the natural gas
produced and delivered by our managing general partner and its affiliates, which
includes us and its other partnerships, subject to certain exceptions. Most of
our natural gas, however, will not be sold pursuant to the agreement with
Amerada Hess Corporation because of the exceptions in that agreement. The
pertinent exceptions are:
o natural gas sold through interconnects established after the date of
the agreement with Amerada Hess Corporation which includes the
majority of the natural gas produced from wells in Fayette County; and
o natural gas that is produced from well(s) operated by a third-party or
which is subject to an agreement under which a third-party was to
arrange for the gathering and sale of the natural gas such as natural
gas produced from wells in Armstrong County, Pennsylvania, McKean
County, Pennsylvania and Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee.
Our managing general partner cannot predict whether this will change in the
future.
The delivery and pricing arrangements with our natural gas purchasers, including
UGI Energy Services, Amerada Hess Corporation, U.S. Energy Exploration
Corporation, M&M Royalty Ltd. and Duke Energy, are usually for a one or two year
period. The price is tied to the New York Mercantile Exchange Commission
("NYMEX") monthly futures contracts price, which is reported daily in the Wall
Street Journal, with an additional premium paid because of the location of the
natural gas (the Appalachian Basin) in relation to the natural gas market, which
is referred to as the "basis." The premium over quoted prices on the NYMEX
received by our managing general partner and its affiliates has ranged between
$.34 and $.65 per mcf during the past three fiscal years.
Pricing for natural gas and oil has been volatile and uncertain for many years.
To limit our exposure to changes in natural gas prices our managing general
partner uses hedges through its natural gas purchasers, as described below, and
through contracts including regulated NYMEX futures and options contracts and
non-regulated over-the-counter futures contracts with qualified counterparties.
The futures contracts employed by our managing general partner are commitments
to purchase or sell natural gas at future dates and generally cover one-month
periods for up to 24 months in the future. To assure that the financial
instruments will be used solely for hedging price risks and not for speculative
purposes, our managing general partner has established a committee to assure
that all financial trading is done in compliance with the managing general
partner's hedging policies and procedures. Our managing general partner does not
intend to contract for positions that it cannot offset with actual production.
Our natural gas purchasers, including UGI Energy Services and Amerada Hess
Corporation, also use NYMEX based financial instruments to hedge their pricing
exposure and make price hedging opportunities available to our managing general
partner for us and our managing general partner's other partnerships. The
majority of our managing general partner's hedges are implemented through the
natural gas purchasers. These transactions are similar to NYMEX based futures
contracts, swaps and options, but also require firm delivery of the hedged
quantity. Thus, our managing general partner limits these arrangements to much
smaller quantities of natural gas than those projected to be available at any
delivery point. Other than these hedges, we are not required to provide any
fixed and determinable quantities of gas under any agreement. Also, the price
paid by UGI Energy Services, Amerada Hess Corporation and any other third-party
marketers for certain volumes of natural gas sold under these hedge agreements
may be significantly different from the underlying monthly spot market value.
5
The portion of our natural gas that is hedged and the manner in which it is
hedged (e.g. fixed pricing, floor and/or costless collar pricing which is a
floor price with a cap, etc.) changes from time to time. As of April 8, 2005,
our overall price hedging position for the future months ending March, 2007 was
approximately as follows:
o 65% was hedged with a fixed price;
o 1% was hedged with a floor price and/or costless collar price; and
o 34% was not hedged and was subject to market based pricing.
Crude oil produced from our wells will flow directly into storage tanks where it
will be picked up by the oil company, a common carrier, or pipeline companies
acting for the oil company which is purchasing the crude oil. Unlike natural
gas, crude oil does not present any transportation problem. Our managing general
partner anticipates selling any oil produced by our wells to regional oil
refining companies at the prevailing spot market price for Appalachian crude oil
in spot sales.
MAJOR CUSTOMERS. Our natural gas and oil is sold under contract to various
purchasers. For the period ended December 31, 2004, sales to UGI Energy
Services, Inc., First Energy Solutions Corporation (which is now Amerada Hess
Corporation) and American Refining Group accounted for 35%, 18% and 17%
respectively, of total revenues. No other customer accounted for more than 10%
of our total revenues for the period ended December 31, 2004. However, American
Refining Group is an oil purchaser, and the wells that we prepaid in 2004 and
which we are drilling and completing in 2005 (69% of our total estimated net
wells) will produce natural gas predominantly. Thus, we do not anticipate that
American Refining Group will account for such a high percentage of our total
revenues in future years.
COMPETITION. The energy industry is intensely competitive in all of its aspects.
Competition arises not only from numerous domestic and foreign sources of
natural gas and oil, but also from other industries that supply alternative
sources of energy. In selling our natural gas and oil, product availability and
price are our principal means of competition.
We may also encounter competition in obtaining drilling and operating services
from third-party providers. Any competition we encounter could delay the
drilling and/or operating of our wells, and thus delay the distribution of our
revenues to our participants.
While it is impossible for us to accurately determine our comparative position
in the natural gas and oil industry, we do not consider our operations to be a
significant factor in the industry.
6
MARKETS. The availability of a ready market for natural gas and oil, and the
price obtained, depends on numerous factors beyond our control as described
below in "Risk Factors - Risks Relating to Our Business." During fiscal 2004,
2003, and 2002 our managing general partner did not experience problems in
selling its and its affiliates' natural gas and oil, although prices varied
significantly during and after this period.
GOVERNMENTAL REGULATION
REGULATION OF PRODUCTION. The production of natural gas and oil is subject to
regulation under a wide range of local, state and federal statutes, rules,
orders and regulations. Federal, state and local statutes and regulations
require permits for drilling operations, drilling bonds and reports concerning
operations. All of the states in which we own and operate properties have
regulations governing conservation matters, including the regulation of well
spacing and plugging and abandonment of wells.
The effect of these regulations is to limit the number of wells or the locations
where we can drill wells, although we can apply for exemptions to the
regulations to reduce the well spacing. Also, each state generally imposes a
production or severance tax for the production and sale of oil, natural gas and
natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial
penalties. Our competitors in the oil and natural gas industry are subject to
the same regulatory requirements and restrictions that affect our operations.
REGULATION OF TRANSPORTATION AND SALE OF NATURAL GAS. Governmental agencies
regulate the production and transportation of 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 into
intrastate markets, and the Federal Energy Regulatory Commission ("FERC")
regulates the interstate transportation of natural gas.
In the past, the federal government has regulated the prices at which natural
gas could be sold. While sales by producers of natural gas can currently be made
at uncontrolled market prices, Congress could re-enact price controls in the
future. Deregulation of wellhead natural gas sales began with the enactment of
the Natural Gas Policy Act, and in 1989 Congress enacted the Natural Gas
Wellhead Decontrol Act which removed all price and non-price controls affecting
wellhead sales of natural gas effective January 1, 1993. Currently, the price of
natural gas is subject to the supply and demand for the natural gas along with
factors such as the natural gas' BTU content and where the wells are located.
Since 1985 FERC has sought to promote greater competition in natural gas markets
in the United States. Traditionally, natural gas was sold by producers to
interstate pipeline companies which served as wholesalers that resold the
natural gas to local distribution companies for resale to end-users. FERC
changed this market structure by requiring interstate pipeline companies to
transport natural gas for third-parties. In 1992 FERC issued Order 636 and a
series of related orders which required 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 natural gas producers or suppliers. The premise behind FERC Order 636 was
that the interstate pipeline companies had an unfair advantage over other
natural gas producers or suppliers because they could bundle their sales and
transportation services together. FERC Order 636 is designed to ensure that no
natural gas seller has a competitive advantage over another natural gas seller
because it also provides transportation services.
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In 2000 FERC issued Order 637 and subsequent orders to enhance competition by
removing price ceilings on short-term capacity release transactions. It also
enacted other regulatory policies that are intended to enhance competition in
the natural gas market and increase the flexibility of interstate natural gas
transportation. FERC has further required pipeline companies to develop
electronic bulletin boards to provide standardized access to information
concerning capacity and prices.
Oil prices are not regulated, and the price is subject to the supply and demand
for oil, along with qualitative factors such as the gravity of the crude oil and
sulfur content differentials.
The energy industry in general is heavily regulated by federal and state
authorities, including regulation of production, environmental quality and
pollution control. The intent of federal and state regulations generally is to:
o prevent waste;
o protect rights to produce natural gas and oil between owners in a
common reservoir; and
o control contamination of the environment.
Failure to comply with regulatory requirements can result in substantial fines
and other penalties.
State regulatory agencies where a producing natural gas well is located provide
a comprehensive statutory and regulatory scheme for oil and natural gas
operations such as ours, including supervising the production activities and the
transportation of natural gas sold in intrastate markets. Our oil and gas
operations in Pennsylvania are regulated by the Department of Environmental
Resources, Division of Oil and Gas our oil and gas operations in West Virginia
are regulated by the West Virginia Department of Environmental Protection -
Division of Oil and Gas and our oil and gas operations in Tennessee are
regulated by the Tennessee Dept. of Environment & Conservation, Div. of Geology.
Among other things, the regulations involve:
o new well permit and well registration requirements, procedures, and
fees;
o landowner notification requirements;
o certain bonding or other security measures;
o minimum well spacing requirements;
o restrictions on well locations and underground gas storage;
o certain well site restoration, groundwater protection, and safety
measures;
o discharge permits for drilling operations;
o various reporting requirements; and
o well plugging standards and procedures.
8
ENVIRONMENTAL REGULATION. Our drilling and producing operations are subject to
various federal, state, and local laws covering the discharge of materials into
the environment, or otherwise relating to the protection of the environment. The
Environmental Protection Agency and state and local agencies will require us to
obtain permits and take other measures with respect to:
o the discharge of pollutants into navigable waters;
o disposal of wastewater; and
o air pollutant emissions.
If these requirements or permits are violated, there can be substantial civil
and criminal penalties which will increase if there was willful negligence or
misconduct. In addition, we may be subject to fines, penalties and unlimited
liability for cleanup costs under various federal laws such as the Federal Clean
Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, the
Oil Pollution Act of 1990, the Toxic Substance Control Act and the Comprehensive
Environmental Response, Compensation and Liability Act of 1980 for oil and/or
hazardous substance contamination or other pollution caused by our drilling
activities or the well and its production.
Additionally, the well owners' or operators' liability can extend to pollution
costs from situations that occurred before their acquisition of the well.
Pennsylvania, West Virginia and Tennessee have either adopted federal standards
or promulgated their own environmental requirements consistent with the federal
regulations.
We believe we have complied in all material respects with applicable federal and
state regulations and do not expect that these regulations will have a material
adverse impact on our operations. Although compliance may cause delays or
increase our costs, currently we do not believe these costs will be substantial.
However, we cannot predict the ultimate costs of complying with present and
future environmental laws and regulations because these laws and regulations are
constantly being revised, and ultimately they may have a material impact on our
operations or costs to remain in compliance. Additionally, we cannot obtain
insurance to protect against many types of environmental claims.
DISMANTLEMENT, RESTORATION, RECLAMATION AND ABANDONMENT COSTS. When we determine
that a well is no longer capable of producing natural gas or oil in economic
quantities, we must dismantle the well and restore and reclaim the surrounding
area before we can abandon the well. We contract these operations to independent
service providers to which we pay a fee. The contractor will also salvage the
equipment on the well, which we then sell in the used equipment market. Under
the partnership agreement, our managing general partner and our participants are
allocated abandonment costs in the same ratio in which they share in our
production revenues (35% to our managing general partner and 65% to our
participants) and the salvage proceeds are allocated between our managing
general partner and our participants in the same ratio in which they were
charged with our equipment costs (76% to our managing general partner and 24% to
our participants).
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As a consequence of the allocation provisions of the partnership agreement as
described above, our managing general partner generally will receive proceeds
from salvaged equipment at least equal to, and typically exceeding, its share of
the related equipment costs, whereas our participants may have a shortfall. To
cover beginning our participant's potential shortfall, beginning one year after
each of our wells has been placed into production our managing general partner,
as operator, may retain $200 of our revenues per month to cover the estimated
future plugging and abandonment costs of the well. See Notes to Financial
Statements.
EMPLOYEES. We have no employees and rely on our managing general partner for
management. See Item 5 "Directors and Executive Officers."
RISK FACTORS
Statements made by us that are not strictly historical facts are
"forward-looking" statements that are based on current expectations about our
business and assumptions made by our managing general partner. These statements
are subject to risks and uncertainties that exist in our operations and business
environment that could result in actual outcomes and results that are materially
different than predicted. The following section entitled "Risks Relating to Our
Business" includes some, but not all, of those factors or uncertainties.
RISKS RELATING TO OUR BUSINESS
NATURAL GAS AND OIL PRICES ARE VOLATILE AND A SUBSTANTIAL DECREASE IN PRICES,
PARTICULARLY NATURAL GAS PRICES, WOULD DECREASE OUR REVENUES, OUR CASH
DISTRIBUTIONS AND THE VALUE OF OUR PROPERTIES AND COULD REDUCE OUR MANAGING
GENERAL PARTNER'S ABILITY TO LOAN US FUNDS AND MEET ITS ONGOING OBLIGATIONS TO
INDEMNIFY OUR INVESTOR GENERAL PARTNERS AND PURCHASE UNITS UNDER OUR PRESENTMENT
FEATURE. A substantial decrease in natural gas and oil prices, particularly
natural gas prices, would decrease our revenues and the value of our natural gas
and oil properties. Our future financial condition and results of operations,
and the value of our natural gas and oil properties, will depend on market
prices for natural gas and, to a much lesser extent, oil. Further, if natural
gas and oil prices decrease during the first years of production from our wells,
which is when the wells typically achieve their greatest level of production,
there would be a greater adverse effect on our distributions to our participants
than price decreases in later years when the wells have a lower level of
production. Natural gas and oil prices historically have been volatile and will
likely continue to be volatile in the future. Prices our managing general
partner has received during its past three fiscal years for its natural gas have
ranged from a high of $6.16 per mcf in the quarter ended June 30, 2004 to a low
of $3.39 per mcf in the quarter ended December 31, 2001.
Prices for natural gas and oil are dictated by supply and demand factors. For
example, reduced natural gas demand and/or excess natural gas supplies will
result in lower prices. Other factors affecting the price and/or marketing of
natural gas and oil production, which are beyond our control and cannot be
accurately predicted, are the following:
o the proximity, availability, and capacity of pipeline and other
transportation facilities;
o competition from other energy sources such as coal and nuclear energy;
o competition from alternative fuels when large consumers of natural gas
are able to convert to alternative fuel use systems;
10
o local, state, and federal regulations regarding production and
transportation;
o the general level of market demand for natural gas and oil on a
regional, national and worldwide basis;
o fluctuating seasonal supply and demand for natural gas and oil because
of various factors such as home heating requirements in the winter
months;
o political instability, terrorist acts and/or war in natural gas and
oil producing countries;
o the amount of domestic production of natural gas and oil;
o the amount of foreign imports of natural gas and oil, including liquid
natural gas from Canada; and
o the actions of the members of the Organization of Petroleum Exporting
Countries ("OPEC"), which include production quotas for petroleum
products from time to time with the intent of increasing, maintaining,
or decreasing price levels.
For example, the North American Free Trade Agreement ("NAFTA") eliminated trade
and investment barriers in the United States, Canada, and Mexico. From time to
time since then there have been increased imports into the United States of
Canadian natural gas. Without a corresponding increase in demand in the United
States, the imported natural gas would have an adverse effect on both the price
and volume of natural gas sales from our wells.
These factors and the volatility of the energy markets make it extremely
difficult to predict future natural gas and oil price movements with any
certainty. Price decreases would reduce the amount of our cash flow available
for distribution to our participants and could make some of our reserves
uneconomic to produce which would reduce our reserves and cash flow.
Additionally, price decreases may cause the lenders under our managing general
partner's credit facility to reduce its borrowing base because of lower revenues
or reserve values, which would reduce our managing general partner's liquidity,
and, possibly, require mandatory loan repayments from our managing general
partner. This would reduce our managing general partner's ability to loan us
money or to meet its ongoing partnership obligations, such as indemnification of
the investor general partners for liabilities in excess of their pro rata share
of partnership assets and insurance proceeds and purchasing units presented by a
participant, although this presentment right may be suspended by the managing
general partner if it determines, in its sole discretion, that it does not have
the necessary cash flow or cannot arrange for financing or other considerations
for this purpose on reasonable terms.
Further, natural gas and oil prices do not necessarily move in tandem. Because
the majority of our proved reserves are currently natural gas reserves, we are
more susceptible to movements in natural gas prices. Also, even though hedging
provides us some protection against falling natural gas prices, hedging also
could reduce the potential benefits of price increases if at the time the
natural gas is to be delivered the spot market natural gas price is higher than
the price paid under the hedging arrangement.
11
DRILLING WELLS IS HIGHLY SPECULATIVE AND WE COULD DRILL SOME WELLS WHICH ARE
NONPRODUCTIVE OR WHICH ARE PRODUCTIVE, BUT FAIL TO RETURN THE COSTS OF DRILLING
AND OPERATING THEM, AND THE DRILLING OF SOME OF OUR WELLS COULD BE CURTAILED,
DELAYED OR CANCELLED IF UNEXPECTED EVENTS OCCUR. The amount of recoverable
natural gas and oil reserves may vary significantly from well to well. We may
drill some wells which are nonproductive (i.e. "dry holes"), or wells that,
while profitable on an operating basis, do not produce sufficient net revenues
to return a profit after drilling, operating and other costs are taken into
account. The geologic data and technologies available do not allow us to know
conclusively before drilling a well that natural gas or oil is present or may be
produced economically.
The cost of drilling, completing and operating a well is often uncertain. For
example, our managing general partner has recently experienced an increase in
the cost of tubular steel as a result of rising steel prices. This has increased
our well costs since our wells are drilled on a cost plus 15% basis.
Further, some of our drilling operations may be curtailed, delayed or cancelled
as a result of many factors, including:
o title problems;
o environmental or other regulatory concerns;
o costs of, or shortages or delays in the availability of, oil field
services and equipment;
o unexpected drilling conditions;
o unexpected geological conditions;
o adverse weather conditions; and
o equipment failures or accidents.
Any one or more of the factors discussed above could reduce or delay our receipt
of drilling and production revenues, thereby reducing distributions to our
participants. As discussed in Item 3 "Properties," many of our prepaid wells are
not yet completed and online.
OUR MANAGING GENERAL PARTNER'S MANAGEMENT OBLIGATIONS TO US ARE NOT EXCLUSIVE,
AND IF IT DOES NOT DEVOTE THE NECESSARY TIME TO OUR MANAGEMENT THERE COULD BE
DELAYS IN PROVIDING TIMELY REPORTS AND DISTRIBUTIONS TO OUR PARTICIPANTS, AND
OUR MANAGING GENERAL PARTNER, SERVING AS OPERATOR OF OUR WELLS, MAY NOT
SUPERVISE THE WELLS CLOSELY ENOUGH. We do not have any officers, directors or
employees. Instead, we rely totally on our managing general partner and its
affiliates for our management. Our managing general partner is required to
devote to us the time and attention that it considers necessary for the proper
management of our activities. However, our managing general partner and its
affiliates currently are, and will continue to be, engaged in other natural gas
and oil activities, including other partnerships and unrelated business ventures
for their own account or for the account of others, during our term. This
creates a continuing conflict of interest in allocating management time,
services, and other activities among us and its other activities. If our
managing general partner does not devote the necessary time to our management,
there could be delays in providing timely annual and semi-annual reports, tax
information and cash distributions to our participants. Also, if our managing
general partner, serving as the operator of our wells, does not supervise the
wells closely enough, for example, there could be delays in undertaking remedial
operations on a well, if necessary, to increase the production of natural gas
and/or oil from the well. However, our managing general partner intends to
allocate its management time, services and other functions on an as-needed basis
consistent with its fiduciary duties among us and its other activities so that
our partnership administration duties and our natural gas and oil operations are
managed properly.
12
CURRENT CONDITIONS MAY CHANGE AND REDUCE OUR PROVED RESERVES, WHICH COULD REDUCE
OUR REVENUES. A participant will be able to recover his investment in us only
through our distribution of the sales proceeds from the production of natural
gas and oil from productive wells. The quantity of natural gas and oil in a
well, which is referred to as its reserves, decreases over time as the natural
gas and oil is produced until the well is no longer economical to operate. Our
proved reserves will decline as reserves are produced, and once all of our wells
are online our distributions to our participants generally will decrease each
year until our wells are depleted.
Our proved reserves at December 31, 2004 are set forth in Item 3. Properties -
Natural Gas and Oil Reserve Information. Under current conditions, our managing
general partner is reasonably certain that those proved reserves will be
produced over the life of our wells. However, there is an element of uncertainty
in all estimates of proved reserves, and current conditions, such as natural gas
and oil prices and the costs of operating our wells and transporting our natural
gas, could change in the future and could reduce the amount of our current
proved reserves. Thus, our revenues from the sale of our natural gas and oil
production from our wells may vary significantly from our expectations
associated with the current estimated proved reserves of our wells. We base our
estimates of our proved natural gas and oil reserves and future net revenues
from those reserves on analyses that rely on various assumptions, including
those required by the SEC, as to natural gas and oil prices, taxes, development
expenses, capital expenses, operating expenses and availability of funds. Any
significant variance in the future in these assumptions, and, in our case,
assumptions concerning future natural gas prices, could materially affect the
estimated quantity of our reserves. Actual production, natural gas and oil
prices, taxes, development expenses, operating expenses, availability of funds
and quantities of recoverable natural gas and oil reserves in the future may
vary substantially from our estimates or estimates contained in the reserve
reports referred to in Item 3 "Properties."
Our properties also may be susceptible to hydrocarbon drainage from production
by other operators on adjacent properties. In addition, our proved reserves may
be revised downward in the future based on production history, results of future
exploration and development in the area, prevailing natural gas and oil prices,
governmental regulation and other changes in current conditions, many of which
are beyond our control.
GOVERNMENT REGULATION OF THE OIL AND NATURAL GAS INDUSTRY IS STRINGENT AND COULD
CAUSE US TO INCUR SUBSTANTIAL UNANTICIPATED COSTS FOR REGULATORY COMPLIANCE,
ENVIRONMENTAL REMEDIATION OF OUR WELL SITES (WHICH MAY NOT BE FULLY INSURED) AND
PENALTIES, AND OUR DRILLING OPERATIONS MAY BE DELAYED OR LIMITED. We are subject
to complex laws that can affect the cost, manner or feasibility of doing
business. Exploration, development, production and sales of natural gas and oil
are subject to extensive federal, state and local regulations. We discuss our
regulatory environment in more detail in "- Governmental Regulation." We may be
required to make large expenditures to comply with these regulations. Failure to
comply with these regulations may result in the suspension or termination of our
operations and subject us to administrative, civil and criminal penalties. Other
regulations may limit our operations. For example, "frost laws" prohibit
drilling and other heavy equipment from using certain roads during winter. This
is important to us because in 2004 we prepaid the costs of certain wells,
including the currently deductible intangible drilling costs of the wells, and
the drilling of each of the prepaid wells was to begin on or before March 30,
2005 under our drilling and operating agreement. Government regulations such as
the "frost laws" could delay the drilling and completion of our prepaid wells.
The drilling of all of our prepaid wells, however, began on or before March 30,
2005. Also, governmental regulations could change in ways that substantially
increase our costs, thereby reducing our return on invested capital, revenues
and net income.
13
Our operations may incur substantial liabilities to comply with environmental
laws and regulations. Our natural gas and oil operations are subject to
stringent federal, state and local laws and regulations relating to the release
or disposal of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may:
o require the acquisition of a permit before drilling commences;
o restrict the types, quantities, and concentration of substances that
can be released into the environment in connection with drilling and
production activities;
o limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands, and other protected areas; and
o impose substantial liabilities for pollution resulting from our
operations.
Failure to comply with these laws and regulations may result in the assessment
of administrative, civil, and criminal penalties, incurrence of investigatory or
remedial obligations, or the imposition of injunctive relief.
Changes in environmental laws and regulations occur frequently, and any changes
that result in more stringent or costly waste handling, storage, transporting,
disposal or cleanup requirements could require us to make significant
expenditures to maintain compliance or could restrict our methods or times of
operation. Under these environmental laws and regulations, we could be held
strictly liable for the removal or remediation of previously released materials
or property contamination regardless of whether we were responsible for the
release or if our operations were standard in the industry at the time they were
performed. We discuss the environmental laws that affect our operations in more
detail under "Governmental Regulation - Environmental Regulation."
Pollution and environmental risks generally are not fully insurable. The
occurrence of an event that is not covered, or not fully covered, by insurance
could reduce our revenues and the value of our assets.
OUR NATURAL GAS AND OIL ACTIVITIES ARE SUBJECT TO DRILLING AND OPERATING HAZARDS
WHICH COULD RESULT IN SUBSTANTIAL LOSSES TO US. Well blowouts, pipeline ruptures
and other operating and environmental problems could result in substantial
losses to us. Well blowouts, cratering, explosions, uncontrollable flows of
natural gas, oil or well fluids, fires, formations with abnormal pressures,
pipeline ruptures or spills, pollution, releases of toxic gas and other
environmental hazards and risks are inherent drilling and operating hazards for
us. The occurrence of any of those hazards could result in substantial losses to
us, including liabilities to third-parties or governmental entities for damages
resulting from the occurrence of any of those hazards and substantial
investigation, litigation and remediation costs.
14
OUR TOTAL CASH DISTRIBUTIONS DURING OUR FIRST FIVE YEARS MAY BE LESS THAN $2,500
PER UNIT PER YEAR. If our participants' cash distributions from us are less than
a 10% return of their capital (which is $2,500 per Unit based on a $25,000 Unit
regardless of the actual price paid) for each of the first five 12-month periods
beginning with our first cash distributions from operations, then our managing
general partner has agreed to subordinate a portion of its share of our net
production revenues. However, if our wells produce only small natural gas and
oil volumes, and/or natural gas and oil prices decrease, then even with
subordination our participants may not receive the 10% return of capital for
each of the first five years as described above. Also, at any time during the
subordination period our managing general partner is entitled to an additional
share of our revenues to recoup previous subordination distributions to the
extent the participants' cash distributions from us exceed the 10% return of
capital described above. A more detailed discussion of our managing general
partner's subordination obligation is set forth in Item 11 "Description of
Registrant's Securities to be Registered - Distributions and Subordination."
Also see "- Current Conditions May Change and Reduce Our Proved Reserves, Which
Could Reduce Our Revenues."
INCREASES IN DRILLING AND OPERATING COSTS COULD DECREASE OUR NET REVENUES FROM
OUR WELLS. The unavailability or high cost of additional drilling rigs,
equipment, supplies, personnel and oil field services, such as increased costs
for tubular steel, have increased our drilling completing and operating costs to
some degree as compared to those well costs in our managing general partner's
prior partnerships, and could decrease our net revenues from our wells.
Shortages of drilling rigs, equipment, supplies or personnel potentially could
have delayed the drilling of our wells, which would have delayed our receipt of
production revenues from the wells. However, our drilling operations have not
been delayed.
OUR LIMITED OPERATING HISTORY CREATES GREATER UNCERTAINTY REGARDING OUR ABILITY
TO OPERATE PROFITABLY. We have a limited history of operating our wells which
could indicate the results that we may achieve in the future. Our success
depends on generating sufficient revenues by producing sufficient quantities of
natural gas and oil from our wells and then marketing that natural gas and oil
at sufficient prices to pay the operating costs of our wells and our
administrative costs of conducting business as a partnership, and still provide
a reasonable rate of return on our participants' investment in us. If we are
unable to pay our costs, then we may need to borrow funds from our managing
general partner, which is not contractually obligated to make any loans to us,
shut-in or curtail production from some of our wells, or attempt to sell some of
our wells, which we may not be able to do on terms that are acceptable to us.
Also, the events set forth below could decrease our revenues from the wells
and/or increase our expenses of operating our wells:
o decreases in the price of natural gas and oil, which are volatile;
o changes in the oil and gas industry, including changes in
environmental regulations which could increase our costs of operating
our wells in compliance with any new environmental regulations;
o an increase in third-party costs for equipment or services, or an
increase in gathering and compression fees for transporting our
natural gas production; and
o problems with one or more of our wells which could require repairing
or performing other remedial work on a well or providing additional
equipment for the well.
15
COMPETITION MAY REDUCE OUR REVENUES FROM THE SALE OF OUR NATURAL GAS.
Competition from other natural gas producers and marketers in the Appalachian
Basin, as well as competition from alternative energy sources, may make it more
difficult to market our natural gas. Our competitors may be able to offer their
natural gas to natural gas purchasers on better terms, such as lower prices or a
greater volume of natural gas that can be delivered to the purchaser, which we
cannot match. Also, other energy sources such as coal may be available to the
purchasers at a lower price. As a result, we may have to seek other natural gas
purchasers which may pay lower prices for our natural gas and we may incur
higher transportation and compression fees if we sell our natural gas to these
other natural gas purchasers. In this event, our revenues from the sale of our
natural gas would be reduced.
WE SELL OUR NATURAL GAS TO A LIMITED NUMBER OF PURCHASERS WITHOUT GUARANTEED
PRICES, AND IF THE PRICES PAID BY THE PURCHASERS DECREASE, OUR REVENUES ALSO
WILL DECREASE, AND IF A PURCHASER STOPS BUYING SOME OR ALL OF OUR NATURAL GAS,
THE SALE OF OUR NATURAL GAS COULD BE DELAYED UNTIL WE FIND ANOTHER PURCHASER AND
THE SUBSTITUTE PURCHASER WE FIND MAY PAY A LOWER PRICE, WHICH WOULD REDUCE OUR
REVENUES. We will depend primarily on a limited number of natural gas purchasers
to purchase the majority of our natural gas production as described in
"General - Sale of Natural Gas and Oil Production," and "General - Major
Customers," above, and we will not be guaranteed a specific natural gas price,
other than through hedging. For example, for the period ended December 31, 2004,
UGI Energy Services, Inc. and First Energy Solutions Corporation (which is now
Amerada Hess Corporation) accounted for 35% and 18%, respectively, of our total
revenues from the sale of natural gas. The only other purchaser which accounted
for more than 10% of our revenues was American Refining Group, an oil purchaser,
which accounted for 17% of our total revenues for the period ended December 31,
2004. As described above in "General - Major Customers," however, we do not
expect that American Refining Group will account for such a significant portion
of our total revenues after we have drilled and completed all of our remaining
wells, which will predominantly produce natural gas. Thus, if our current
purchasers, including UGI Energy Services, Inc. and Amerada Hess Corporation
were to pay a lower price for our natural gas in the future, our revenues would
decrease. Also, if our current purchasers, including UGI Energy Services, Inc.
and Amerada Hess Corporation, were to begin buying a reduced percentage of our
natural gas, or stopped buying any of our natural gas, the sale of our natural
gas could be delayed until we find another purchaser and the substitute
purchaser or purchasers we do find may pay lower prices for our natural gas,
which would reduce our revenues. However, our managing general partner has not
experienced any problems with selling natural gas in the past three fiscal years
as discussed in "General - Markets," above.
WE COULD INCUR DELAYS IN PAYMENT, OR SUBSTANTIAL LOSSES IF PAYMENT IS NOT MADE,
FOR NATURAL GAS WE PREVIOUSLY DELIVERED TO THE PURCHASER, WHICH COULD DELAY OR
REDUCE OUR REVENUES AND CASH DISTRIBUTIONS. There is a credit risk associated
with a natural gas purchaser's ability to pay. We may not be paid or may
experience delays in receiving payment for natural gas that has already been
delivered. In this event, our revenues and cash distributions to our
participants also would be delayed or reduced. In accordance with industry
practice, we typically will deliver natural gas to a purchaser for a period of
up to 60 to 90 days before we receive payment. Thus, it is possible that we may
not be paid for natural gas that already has been delivered if the natural gas
purchaser fails to pay for any reason, including bankruptcy. This ongoing credit
risk also may delay or interrupt the sale of our natural gas. This credit risk
may also reduce the price benefit derived by us from our managing general
partner's natural gas hedging as described in "Sale of Natural Gas and Oil
Production," since the majority of our managing general partner's natural gas
hedges are implemented through the natural gas purchasers.
16
IF THE THIRD-PARTIES WHICH ARE PARTICIPATING IN DRILLING SOME OF OUR WELLS FAIL
TO PAY THEIR SHARE OF THE WELL COSTS, WE WOULD HAVE TO PAY THOSE COSTS IN ORDER
TO GET THE WELLS DRILLED, AND IF WE ARE NOT REIMBURSED THE INCREASED COSTS WOULD
REDUCE OUR CASH FLOW AND POSSIBLY COULD REDUCE THE NUMBER OF WELLS WE CAN DRILL.
Third-parties have participated with us in drilling some of our wells. Financial
risks exist when the cost of drilling, equipping, completing, and operating
wells is shared by more than one person. If we pay our share of the costs, but
the other interest owner does not pay its share of the costs, then we would have
to pay the costs of the defaulting party. In this event, we would receive the
defaulting party's revenues from the well, if any, under penalty arrangements
set forth in the operating agreement, which may, or may not, be sufficient to
cover the additional costs we paid and, if not, then the increased costs would
reduce our cash flow and the number of wells we can drill unless we borrow funds
to cover the additional costs or the costs of drilling our other wells is less
than expected and those excess funds are used to pay the additional costs that
should have been paid by the third-party. However, the third-parties
participating in some of our wells currently have not defaulted on any of their
respective obligations for those wells.
WE EXPECT TO INCUR COSTS IN CONNECTION WITH EXCHANGE ACT COMPLIANCE AND WE MAY
BECOME SUBJECT TO LIABILITY FOR ANY FAILURE TO COMPLY, WHICH WILL REDUCE OUR
CASH AVAILABLE FOR DISTRIBUTION. As a result of our obligation to register our
securities with the SEC under the Exchange Act, we will be subject to Exchange
Act Rules and related reporting requirements. This compliance with the reporting
requirements of the Exchange Act will require timely filing of quarterly reports
on Form 10-QSB, annual reports on Form 10-KSB and current reports on Form 8-K,
among other actions. Further, recently enacted and proposed laws, regulations
and standards relating to corporate governance and disclosure requirements
applicable to public companies, including the Sarbanes-Oxley Act of 2002 (the
"Sarbanes-Oxley Act") and new SEC regulations, have increased the costs of
corporate governance, reporting and disclosure practices which are now required
of us. In addition, these laws, rules and regulations create new legal grounds
for administrative enforcement and civil and criminal proceedings against us in
case of non-compliance, which increases our risks of liability and potential
sanctions. All of the additional compliance costs described above will decrease
the amount of cash available to us to distribute to our participants.
WE INTEND TO PRODUCE NATURAL GAS AND/OR OIL FROM OUR WELLS UNTIL THEY ARE
DEPLETED, REGARDLESS OF ANY CHANGES IN CURRENT CONDITIONS, WHICH COULD RESULT IN
LOWER RETURNS TO OUR PARTICIPANTS AS COMPARED WITH OTHER TYPES OF INVESTMENTS
WHICH CAN ADAPT TO FUTURE CHANGES AFFECTING THEIR PORTFOLIOS. Our natural gas
and oil properties are relatively illiquid because there is no public market for
working interests in natural gas and oil wells. In addition, one of our
investment objectives is to continue to produce natural gas and oil from our
wells until the wells are depleted. Thus, unlike mutual funds, for example,
which can vary their portfolios in response to changes in future conditions, we
do not intend, and in all likelihood would be unable, to vary our portfolio of
wells in response to future changes in economic and other conditions such as
decreases or increases in natural gas or oil prices, or increased operating
costs of our wells.
17
SINCE OUR MANAGING GENERAL PARTNER IS NOT CONTRACTUALLY OBLIGATED TO LOAN FUNDS
TO US, WE COULD HAVE TO CURTAIL OPERATIONS OR SELL PROPERTIES IF WE NEED
ADDITIONAL FUNDS AND OUR MANAGING GENERAL PARTNER DOES NOT MAKE THE LOAN. We
believe that our ongoing operating and maintenance costs for our productive
wells will be paid through revenues we receive from the sale of our natural gas
and oil production as discussed in Item 2 "Financial Information." However, a
shortfall in funds to pay for our ongoing expenses may arise, for example, for
costs associated with repairing or performing other remedial work on a well. If
this were to occur, we expect that we would borrow the necessary funds from our
managing general partner or its affiliates, which are not contractually
committed to make a loan. The amount we may borrow may not at any time exceed 5%
of our total subscriptions and no borrowings will be obtained from
third-parties. If, for any reason, our managing general partner did not loan us
the funds needed for repairing or performing other remedial work on a well, then
we might have to curtail our operations on the well or wells which needed the
remedial work or we may attempt to sell one or more of our wells, although we
may not be able to do so on terms that are acceptable to us.
ITEM 2. FINANCIAL INFORMATION.
The following table sets forth selected financial data for the period ended
December 31, 2004. We derived the financial data for the period ended December
31, 2004 from our financial statements, which were audited by Grant Thornton
LLP, independent public registered accountants, and are included in this
Form 10.
18
FOR THE PERIOD JUNE 21, 2004
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2004
----------------------------
INCOME STATEMENT DATA:
Revenues:
Gas and oil production .................................................... $ 840,560
----------------------------
Total revenues........................................................ 840,560
Costs and expenses:
Gas and oil production..................................................... 11,100
Transmission............................................................... 34,468
Well services.............................................................. 24,131
General and administration................................................. 9,381
Depreciation, depletion and amortization................................... 630,224
----------------------------
Total costs and expenses........................................................ 709,304
----------------------------
Net income...................................................................... $ 131,256
============================
Basic and diluted net earnings per limited partnership unit..................... $ 17
============================
FOR THE PERIOD JUNE 21, 2004
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2004
----------------------------
OPERATION DATA:
Net annual production volumes:
Natural gas (mmcf) (1) .................................................... 127
Oil (mbbls)................................................................ 1
----------------------------
Total (mmcfs)................................................................... 133
Average sales price:
Natural gas (per mcf)...................................................... $ 6.22
Oil (per bbl) ............................................................. $ 45.07
OTHER FINANCIAL INFORMATION:
Net cash provided by operating activities....................................... -
Capital expenditures ........................................................... 31,531,100
EBITDA (2)..................................................................... $ 761,479
19
FOR THE PERIOD JUNE 21, 2004
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2004
----------------------------
BALANCE SHEET DATA:
Total assets.................................................................... $ 43,939,463
=============================
Total liabilities ............................................................. $ 999,775
=============================
Stockholders' equity............................................................ $ 42,939,688
=============================
- ----------
(1) Excludes sales of residual gas and sales to landowners.
(2) We define EBITDA as earnings before interest, taxes, depreciation,
depletion and amortization. EBITDA is not a measure of performance
calculated in accordance with accounting principles generally accepted
in the United States of America or GAAP. Although not prescribed under
GAAP, we believe the presentation of EBITDA is relevant and useful
because it helps out investors to understand our operation performance
and makes it easier to compare our results with other companies that
have different financing and capital structures or tax rates. EBITDA
should not be considered in isolation of or as a substitute for, net
income as an indicator of operation performance or cash flows from
operating activities as a measure of liquidity. EBITDA, as we
calculate it may not be comparable to EBITDA measures reported by
other companies. In addition, EBITDA does not represent funds
available for discretionary use. The following reconciles EBITDA to
our income from continuing operations for the periods indicated.
FOR THE PERIOD JUNE 21, 2004
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2004
----------------------------
Income from continuing operations............................................ $ 131,255
Plus depreciation, depletion and amortization ............................... 630,224
-----------------------------
EBITDA....................................................................... $ 761,479
=============================
FORWARD-LOOKING STATEMENTS. When used in this Form 10, the words "believes"
"anticipates" "expects" and similar expressions are intended to identify
forward-looking statements. Such statements are subject to certain risks and
uncertainties more particularly described in Item 1 of this Form 10. These risks
and uncertainties could cause actual results to differ materially. Readers are
cautioned not to place undue reliance on these forward-looking statements, which
speak only as of the date hereof. We undertake no obligation to publicly release
the results of any revisions to forward-looking statements which we may make to
reflect events or circumstances after the date of this Form 10 or to reflect the
occurrence of unanticipated events.
This "Management's Discussion and Analysis or Plan of Operation" should be read
in conjunction with the notes to our financial statements.
RESULTS OF OPERATIONS. The following table sets forth information for the period
June 21, 2004 (date of formation) through December 31, 2004 relating to revenues
recognized and costs and expenses incurred, daily production volumes, average
sales prices and production cost per equivalent unit during the period
indicated:
20
PERIOD ENDED
DECEMBER 31,
2004
------------
Revenues (in thousands):
Gas(1) ............................................................ $ 788
Oil................................................................ $ 53
Production volumes:
Gas (thousands of cubic feet (mcf)/day)............................ 346
Oil (barrels (bbls)/day)........................................... 3
Average sales price:
Gas (per mcf)...................................................... $ 6.22
Oil (per bbl)...................................................... $ 45.07
Production costs:
As a percent of sales.............................................. 8%
Per equivalent mcf................................................. $ .52
- ----------
(1) Excludes sales of residual gas and sales to landowners.
LIQUIDITY AND CAPITAL RESOURCES. Cash used in investing activities was
$31,531,000 for the period ended December 31, 2004, which was used in drilling
contracts paid to our managing general partner. Cash provided by financing
activities was $31,531,000 which came from investor capital contributions for
the period ended December 31, 2004.
Our managing general partner believes that we have adequate capital to develop
approximately 175 gross wells under our drilling and operating agreement. Our
wells will be drilled primarily in western Pennsylvania and Tennessee. Funds
contributed by our participants and our managing general partner after our
formation will be the only funds available to us for drilling activities, no
other wells will be drilled after this initial group. Although we estimate that
175 gross development wells will be drilled, we cannot guarantee that all of our
proposed wells will be drilled or completed. Each of our proposed wells is
unique and the ultimate costs incurred may be more or less than our current
estimates.
Our ongoing operating and maintenance costs for the next 12-month period are
expected by our managing general partner to be fulfilled through revenues from
the sale of our gas and oil production. Although we do not anticipate a
shortfall to pay for our ongoing expenses, if one were to occur, funds will be
borrowed from our managing general partner or its affiliates, which are not
contractually committed to make a loan. The amount we may borrow may not at any
time exceed 5% of our total subscriptions and no borrowings will be obtained
from third parties.
We have not and will not devote any funds to research and development activities
and no new products or services will be introduced. We do not plan to sell any
of our wells and will continue to produce them until they are depleted at which
time they will be plugged and abandoned. We have no employees and rely on our
managing general partner for management.
21
CRITICAL ACCOUNTING POLICIES. The discussion and analysis of our financial
condition and results of operations are based upon our financial statements,
which have been prepared in accordance with accounting principles generally
accepted in the United States of America. The preparation of these financial
statements requires us to make estimates and judgments that affect the reported
amounts of our assets, liabilities, revenues and cost and expenses, and related
disclosure of contingent assets and liabilities. On an on-going basis, we
evaluate our estimates, including those related to oil and gas reserves and
certain accrued liabilities. We base our estimates on historical experience and
on various other assumptions that we believe reasonable under the circumstances,
the results of which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent from other
sources. Actual results may differ from these estimates under different
assumptions or conditions.
We have identified the following policies as critical to our business operations
and the understanding of our results of operations. For a detailed discussion on
the application of these and other accounting policies, see Note 2 of the "Notes
to Financial Statements".
USE OF ESTIMATES. Preparation of the financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
Actual results could differ from these estimates.
RESERVE ESTIMATES. Our estimates of our proved natural gas and oil reserves and
future net revenues from them will be based upon reserve analyses that rely upon
various assumptions, including those required by the SEC, as to natural gas and
oil prices, drilling and operating expenses, capital expenditures, abandonment
costs, taxes and availability of funds. Any significant variance in these
assumptions could materially affect the estimated quantity of our reserves. As a
result, our estimates of our proved natural gas and oil reserves will be
inherently imprecise. Actual future production, natural gas and oil prices,
revenues, taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and oil reserves may vary substantially from our
estimates or estimates contained in the reserve reports. In addition, our proved
reserves may be subject to downward or upward revision based upon production
history, results of future exploration and development, prevailing natural gas
and oil prices, mechanical difficulties, governmental regulation and other
factors, many of which are beyond our control.
IMPAIRMENT OF OIL AND GAS PROPERTIES. We will review our producing oil and gas
properties for impairment on an annual basis and whenever events and
circumstances indicate a decline in the recoverability of their carrying values.
We will estimate the expected future cash flows from our oil and gas properties
and compare such future cash flows to the carrying amount of the oil and gas
properties to determine if the carrying amount is recoverable. If the carrying
amount exceeds the estimated undiscounted future cash flows, we will adjust the
carrying amount of the oil and gas properties to their fair value in the current
period. The factors used to determine fair value include, but are not limited
to, estimates of reserves, future production estimates, anticipated capital
expenditures, and a discount rate commensurate with the risk associated with
realizing the expected cash flows projected. Given the complexities associated
with oil and gas reserve estimates and the history of price volatility in the
oil and gas markets, events may arise that will require us to record an
impairment of our oil and gas properties and there can be no assurance that such
impairments will not be required in the future.
22
DISMANTLEMENT, RESTORATION, RECLAMATION AND ABANDONMENT COSTS. On a periodic
basis, we estimate the costs of future dismantlement, restoration, reclamation
and abandonment of our natural gas and oil-producing properties. We also
estimate the salvage value of equipment recoverable upon abandonment. We account
for abandonment costs using, as discussed in Note 2 to our consolidated
financial statements. As of December 31, 2004, our estimate of salvage values
was greater than or equal to our estimate of the costs of future dismantlement,
restoration, reclamation and abandonment. A decrease in salvage values or an
increase in dismantlement, restoration, reclamation and abandonment costs from
those we have estimated, or changes in our estimates or cost, could reduce our
gross profit from energy operations.
COMMODITY PRICE RISK. Our major market risk exposure in commodities is
fluctuations in the pricing of our gas and oil production. Realized pricing is
primarily driven by the prevailing worldwide prices for crude oil and spot
market prices applicable to United States natural gas production. Pricing for
gas and oil production has been volatile and unpredictable for many years. To
limit our exposure to changing natural gas prices, we use hedges. Our managing
general partner through its hedges seeks to provide a measure of stability in
the volatile environment of natural gas prices. Our risk management objective is
to lock in a range of pricing for expected production volumes.
Third party marketers to which we sell gas also use financial hedges to hedge
their pricing exposure and make price hedging opportunities available to us.
These transactions are similar to NYMEX- based futures contracts, swaps and
options, but also require firm delivery of the hedged quantity. Thus, we limit
these arrangements to much smaller quantities than those projected to be
available at any delivery point. For the year ending December 31, 2005, we
estimate in excess of 20% of our produced natural gas volumes will be sold in
this manner, leaving our remaining production to be sold at contract prices in
the month produced or at spot market prices. We also negotiate with certain
purchasers for delivery of a portion of natural gas we will produce for the
upcoming twelve months. The prices under most of our gas sales contracts are
negotiated on an annual basis and are index-based.
ITEM 3. PROPERTIES.
DRILLING ACTIVITY. As of December 31, 2004 we had drilled and completed 51 gross
wells, which is 47 net wells as shown in the following table. All of the wells
we 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. In addition to the 51 gross wells, which is 47 net
wells, we drilled during 2004 as shown in the following table, approximately
106.40 net wells were prepaid by us in 2004. The drilling of the approximately
106.40 net wells we prepaid in 2004 began on or before March 30, 2005, and those
prepaid wells are not included in the following table.
DEVELOPMENT WELLS
------------------------------------------------------------------------
PRODUCTIVE (1) DRY (2)
----------------------------------- ---------------------------------
GROSS (3) NET (4) GROSS (3) NET (4)
---------------- --------------- --------------- --------------
PERIOD ENDING DECEMBER 31, 2004 47 43 4 4
23
(1) A "productive well" generally means a well that is not a dry hole.
(2) A "dry hole" generally means a well found to be incapable of producing
either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well. The term "completion" refers
to the installation of permanent equipment for the production of oil or
natural gas or, in the case of a dry hole, to the reporting of
abandonment to the appropriate agency.
(3) A "gross" well is a well in which we own a working interest.
(4) A "net" well equals the actual working interest we own 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.
SUMMARY OF PRODUCTIVE WELLS. The table below shows the location by state and the
number of productive gross and net wells in which we own a working interest at
December 31, 2004. All of our wells are classified as natural gas wells.
LOCATION GROSS NET
-------- --------
Pennsylvania........................................... 46 42.35
West Virginia.......................................... 1 .65
Tennessee.............................................. - -
-------- --------
Total ........................................... 47 43.00
======== ========
PRODUCTION. The following table shows the quantities of natural gas and oil
produced (net to our interest), average sales price, and average production
(lifting) cost per equivalent unit of production for the period indicated.
AVERAGE
AVERAGE SALES PRICE (AFTER PRODUCTION
PRODUCTION HEDGING) COST (LIFTING
--------------------------- ------------------------------ COST) PER
PERIOD FROM FIRST PRODUCTION TO OIL (BBLS) GAS (MCF) PER BBL PER MCF (1) MCFE (1)(2)
DECEMBER 31, 2004 ------------ ------------ ------------ -------------- --------------
1,200 126,700 $45.07 $6.22 $.52
(1) "Mcf" means one thousand cubic feet of natural gas. "Mcfe" means one
thousand cubic feet equivalent. "Bbl" means one barrel of oil. Oil
production is converted to mcfe at the rate of six mcf per barrel
("bbl").
(2) Production costs include labor to operate the wells and related
equipment, repairs and maintenance, materials and supplies, property
taxes, severance taxes, insurance, gathering charges and production
overhead.
NATURAL GAS AND OIL RESERVE INFORMATION. The following tables summarize
information regarding our estimated proved natural gas and oil reserves as of
the dates indicated. All of our reserves are located in the United States. We
base our estimates relating to our proved natural gas and oil reserves and
future net revenues of natural gas and oil reserves on internally prepared
reports, which were reviewed by Wright & Company, Inc., energy consultants. In
accordance with SEC guidelines, we make the SEC PV-10 estimates of future net
cash flows from proved reserves using natural gas sales prices in effect as of
the dates of the estimates which are held constant throughout the life of the
properties. We based our estimates of proved reserves on the following year-end
weighted average prices.
24
AT DECEMBER 31, 2004
Natural gas (per mcf)................................................. $7.19
Oil (per bbl)......................................................... $ 39.75
Reserve estimates are imprecise and may change as additional information becomes
available. Furthermore, estimates of natural gas and oil reserves, of necessity,
are projections based on engineering data. There are uncertainties inherent in
the interpretation of this data as well as the projection of future rates of
production and the timing of development expenditures. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact way and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Reserve reports of other engineers might
differ from the reports we prepared, which were reviewed by Wright & Company,
Inc., energy consultants.
Results of drilling, testing and production after the date of the estimate may
justify revision of the estimate. Future prices received from the sale of
natural gas may be different from those we estimated in preparing our reports.
The amounts and timing of future operating, development and abandonment costs
may also differ from those used. Thus, the reserves set forth in the following
tables ultimately may not be produced and the proved undeveloped reserves may
not be developed within the periods anticipated. You should not construe the
estimated PV-10 values as representative of the fair market value of our proved
natural gas properties. PV-10 values are based on projected cash inflows, which
do not provide for changes in natural gas and oil prices or for escalation of
expenses and capital costs. The meaningfulness of these estimates depends on the
accuracy of the assumptions on which they were based.
We evaluate natural gas reserves at constant temperature and pressure. A change
in either of these factors can affect the measurement of natural gas reserves.
In arriving at the estimated future cash flows, we deducted when applicable the
operating costs, development costs, and production-related and ad valorem taxes.
We made no provision for income taxes, and based the estimates on operating
methods and conditions prevailing as of the dates indicated. We cannot assure
you that these estimates are accurate predictions of future net cash flows from
natural gas reserves or their present value. For additional information
concerning our natural gas reserves and estimates of future net revenues, see
Notes to Financial Statements.
25
AT DECEMBER 31, 2004
-------------------------
Natural gas reserves - Proved Reserves (Mcf)(1)(5):
Proved developed reserves (2)...................................... 3,006,000
Proved undeveloped reserves (3).................................... 5,435,700
-------------------------
Total proved reserves of natural gas............................... 8,441,700
=========================
Oil reserves - Proved Reserves (Bbl)(1)(5)
Proved developed reserves (2)...................................... 17,700
Proved undeveloped reserves (3).................................... 13,800
-------------------------
Total proved reserves of oil....................................... 31,500
-------------------------
Total proved reserves (Mcfe)........................................... 8,630,700
=========================
PV-10 estimate of cash flows of proved reserves (4)(5):
Proved developed reserves..........................................$ 9,822,400
Proved undeveloped reserves........................................ 18,032,200
-------------------------
Total PV-10 estimate $ 27,854,600
=========================
(1) "Proved reserves" generally 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 on future conditions. Reservoirs are considered
proved if economic production 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.
(2) "Proved developed oil and gas reserves" generally means reserves that
can be expected to be recovered through existing wells with existing
equipment and operating methods.
(3) "Proved undeveloped reserves" generally means 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.
(4) The present value of estimated future net cash flows is calculated by
discounting estimated future net cash flows by 10% annually.
(5) Please see Regulation S-X rule 4-10 for complete definitions of each
reserve category.
We have not filed any estimates of our natural gas and oil reserves with, nor
were the estimates included in any reports to, any Federal or foreign
governmental agency within the 12 months before the date of this filing. For
additional information concerning our natural gas and oil reserves and
activities, see Notes to Financial Statements.
26
TITLE TO PROPERTIES. We believe that we hold good and indefeasible title to our
properties, in accordance with standards generally accepted in the natural gas
and oil industry, subject to exceptions stated in the opinions of counsel
employed by us in the various areas in which we conduct our activities. We do
not believe that these exceptions detract substantially from our use of any
property. As is customary in the natural gas and oil industry, we conduct only a
perfunctory title examination at the time we acquire a property. Before we
commence drilling operations, we conduct an extensive title examination and we
perform curative work on defects that we deem significant. We have obtained
title examinations for substantially all of our managed producing properties. No
single property represents a material portion of our holdings.
Our properties are subject to royalty, overriding royalty and other outstanding
interests customary in the industry, such as free gas to the landowner-lessor
for home heating requirements, etc. Our properties are also subject to burdens
such as:
o liens incident to operating agreements;
o taxes;
o development obligations under natural gas and oil leases;
o farm-out arrangements; and
o other encumbrances, easements and restrictions.
We do not believe that any of these burdens will materially interfere with our
use of our properties.
ACREAGE. The table below shows the estimated acres of developed and undeveloped
natural gas and oil acreage in which we have an interest, separated by state, at
December 31, 2004.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE (3)
----------------------------------- ---------------------------------
LOCATION GROSS (1) NET (2) GROSS (1) NET (2)
- -------- --------------- ---------------- -------------- ----------------
Pennsylvania ............................... 986.65 959.10 1,702.20 1,573.65
West Virginia............................... 90.00 51.00 330.00 207.00
Tennessee .................................. - - 240.00 240.00
--------------- ---------------- -------------- ----------------
Total ................................ 1,076.65 1,010.10 2,032.20 1,780.65
=============== ================ ============== ================
(1) A "gross" acre is an acre in which we own a working interest.
(2) A "net" acre equals the actual working interest we own 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.
(3) "Undeveloped acreage" means those lease acres on which wells have not
been drilled or completed to a point that would permit the production
of commercial quantities of natural gas and oil regardless of whether
or not the acreage contains proved reserves.
As discussed in Item 1 "Business - Sale of Natural Gas and Oil Production," we
are not required to provide any fixed and determinable quantities of natural gas
under any agreement other than agreements that are the result of limited hedging
agreements with our natural gas purchasers.
27
ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
As of December 31, 2004, we had issued 1,265.38 Units to 634 participants. The
following table, as of December 31, 2004, sets forth the number and percentage
of Units owned and held by:
o beneficial owners of 5% or more of our Units;
o our managing general partner's executive officers and directors; and
o all of the executive officers and directors of our managing general
partner as a group.
The address for each director and executive officer of our managing general
partner is 311 Rouser Road, Moon Township, Pennsylvania 15108.
UNITS
-------------------------------------------
AMOUNT AND NATURE OF
BENEFICIAL OWNER BENEFICIAL OWNERSHIP PERCENT OF CLASS
- ---------------- -------------------- ----------------
DIRECTORS
Freddie M. Kotek................................................ 0 0
Frank P. Carolas................................................ 0 0
Jeffrey C. Simmons............................................. 0 0
Michael L. Staines.............................................. 0 0
NON-DIRECTOR EXECUTIVE OFFICERS
Jack L. Hollander............................................... 0 0
Nancy J. McGurk................................................. 0 0
Michael G. Hartzell............................................. 0 0
Donald R. Laughlin.............................................. 0 0
Karen A. Black.................................................. 0 0
Marci F. Bleichmar.............................................. 0 0
All executive officers and directors as a group ................ 0 0
OTHER OWNERS OF MORE THAN 5% OF OUTSTANDING SHARES
None............................................................ 0 0
We are not aware of any arrangements which may, at a subsequent date, result in
a change in our control.
28
ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS
MANAGING GENERAL PARTNER. We will have no officers, directors or employees.
Instead, Atlas Resources, Inc., a Pennsylvania corporation which was
incorporated in 1979, will serve as our managing general partner. Our managing
general partner depends on its indirect parent company, Atlas America, for
management and administrative functions and financing for capital expenditures.
Our managing general partner pays a management fee to Atlas America for
management and administrative services, which amounted to $23.2 million, $13.1
million, and $10.5 million for our managing general partner's fiscal years ended
September 30, 2004, 2003, and 2002, respectively. As of December 31, 2004, our
managing general partner and its affiliates under Atlas America employ a total
of approximately 205 persons. Our managing general partner and Atlas America are
headquartered at 311 Rouser Road, Moon Township, Pennsylvania 15108, near the
Pittsburgh International Airport, which is also our managing general partner's
primary office.
In 1998, Atlas Energy Group, Inc., the former parent company of our managing
general partner, merged into Atlas America, Inc., a Delaware holding company,
which is a subsidiary of Resource America, Inc., a publicly-traded company. In
May 2004 Resource America conducted a public offering of a portion of its common
stock (the "shares") in Atlas America. Two million six hundred forty-five
thousand shares were registered and sold at a price of at $15.50 per share
resulting in gross proceeds of $41 million of which approximately $3.5 million
was applied to underwriting discounts and commissions and approximately $530,000
of which was applied to related costs. The net proceeds of the offering of $37
million after deducting underwriting discounts were distributed to Resource
America in the form of a repayment of inter-company debt and a non-taxable
dividend. Resource America continues to own approximately 80.2% of Atlas
America's common stock. Also, in May 2004, in connection with the Atlas America
offering, the following officers and key employees of our managing general
partner and Atlas America set forth in "Directors, Executive Officers and
Significant Employees," below, resigned their positions with Resource America
and all of its subsidiaries which are not also subsidiaries of Atlas America:
Mr. Freddie M. Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C. Simmons, Ms. Nancy J.
McGurk, Mr. Michael L. Staines, and Ms. Marci Bleichmar.
Resource America has advised our managing general partner that it intends to
distribute its remaining ownership interest in Atlas America to Resource
America's common stockholders. Resource America expects the distribution to take
the form of a spin-off by means of a tax-free dividend to Resource America
common stockholders of all of Atlas America's common stock owned by Resource
America. Resource America further has advised our managing general partner that
it anticipates that the distribution will occur on or before June 30, 2005, but
it has sole discretion if and when to complete the distribution and its terms.
29
DIRECTORS, EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES. The officers and
directors of our managing general partner will serve until their successors are
elected. The officers, directors and significant employees of our managing
general partner are as follows:
NAME AGE POSITION OR OFFICE
- ---- --- ------------------
Freddie M. Kotek 49 Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas 45 Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons 46 Executive Vice President - Operations and a Director
Jack L. Hollander 48 Senior Vice President - Direct Participation Programs
Nancy J. McGurk 49 Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines 55 Senior Vice President, Secretary and a Director
Michael G. Hartzell 48 Vice President - Land Administration
Donald R. Laughlin 56 Vice President - Drilling and Production
Marci F. Bleichmar 34 Vice President of Marketing
Karen A. Black 44 Vice President - Partnership Administration
Sherwood S. Lutz 53 Senior Geologist/Manager of Geology
Michael W. Brecko 46 Director of Energy Sales
Justin T. Atkinson 31 Director of Due Diligence
Winifred C. Loncar 63 Director of Investor Services
With respect to the biographical information set forth below:
o the approximate amount of an individual's professional time devoted to
the business and affairs of our managing general partner and Atlas
America have been aggregated because there is no reasonable method for
them to distinguish their activities between the two companies; and
o for those individuals who also hold senior positions with other
affiliates of our managing general partner, if it is stated that they
devote approximately 100% of their professional time to our managing
general partner and Atlas America, it is because either the other
affiliates are not currently active in drilling new wells, such as
Viking Resources or Resource Energy, and the individuals are not
required to devote a material amount of their professional time to the
affiliates, or there is no reasonable method to distinguish their
activities between our managing general partner and Atlas America as
compared with the other affiliates of our managing general partner,
such as Viking Resources or Resource Energy.
FREDDIE M. KOTEK. President and Chief Executive Officer since January 2002 and
Chairman of the Board of Directors since September 2001. Mr. Kotek has been
Executive Vice President of Atlas America since February 2004, and served as a
director from September 2001 until February 2004 and served as Chief Financial
Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice
President of Resource America and President of Resource Leasing, Inc. (a
wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he
resigned from Resource America and all of its subsidiaries which are not
subsidiaries of Atlas America. Mr. Kotek was President of Resource Properties
from September 2000 to October 2001 and its Executive Vice President from 1993
to August 1999. Mr. Kotek received a Bachelor of Arts degree from Rutgers
College in 1977 with high honors in Economics. He also received a Master in
Business Administration degree from the Harvard Graduate School of Business
Administration in 1981. Mr. Kotek will devote approximately 95% of his
professional time to the business and affairs of the managing general partner
and Atlas America, and the remainder of his professional time to the business
and affairs of the managing general partner's affiliates.
30
FRANK P. CAROLAS. Executive Vice President - Land and Geology and a Director
since January 2001. Mr. Carolas has been an Executive Vice President of Atlas
America since January 2001 and served as a Director of Atlas America from
January 2002 until February 2004. Mr. Carolas was a Vice President of Resource
America from April 2001 until May 2004 when he resigned from Resource America.
Mr. Carolas served as Vice President of Land and Geology for our managing
general partner from July 1999 until December 2000 and for Atlas America from
1998 until December 2000. Before that Mr. Carolas served as Vice President of
Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent
company of our managing general partner. Mr. Carolas is a certified petroleum
geologist and has been with our managing general partner and its affiliates
since 1981. He received a Bachelor of Science degree in Geology from
Pennsylvania State University in 1981 and is an active member of the American
Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.
JEFFREY C. SIMMONS. Executive Vice President - Operations and a Director since
January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America
since January 2001 and was a Director of Atlas America from January 2002 until
February 2004. Mr. Simmons was a Vice President of Resource America from April
2001 until May 2004 when he resigned from Resource America. Mr. Simmons served
as Vice President of Operations for our managing general partner from July 1999
until December 2000 and for Atlas America from 1998 until December 2000. Mr.
Simmons joined Resource America in 1986 as a senior petroleum engineer and has
served in various executive positions with its energy subsidiaries since then.
Before Mr. Simmons' career with Resource America, he had worked with Core
Laboratories, Inc., of Dallas, Texas, and PNC Bank of Pittsburgh. Mr. Simmons
received his Petroleum Engineering degree from Marietta College in 1981 and his
Masters degree in Business Administration from Ashland University in 1992. Mr.
Simmons devotes approximately 80% of his professional time to the business and
affairs of our managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of our managing general
partner's affiliates, primarily Viking Resources and Resource Energy.
JACK L. HOLLANDER. Senior Vice President - Direct Participation Programs since
January 2002 and before that he served as Vice President - Direct Participation
Programs from January 2001 until December 2001. Mr. Hollander also serves as
Senior Vice President - Direct Participation Programs of Atlas America since
January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak,
concentrating in tax matters and real estate transactions, from 1990 to January
2001, and served as in-house counsel for Integrated Resources, Inc. (a
diversified financial services company) from 1982 to 1990. Mr. Hollander earned
a Bachelor of Science degree from the University of Rhode Island in 1978, his
law degree from Brooklyn Law School in 1981, and a Master of Law degree in
Taxation from New York University School of Law Graduate Division in 1982. Mr.
Hollander is a member of the New York State bar, the Investment Program
Association, and the Financial Planning Association. Mr. Hollander devotes
approximately 100% of his professional time to the business and affairs of our
managing general partner and Atlas America.
31
NANCY J. MCGURK. Senior Vice President since January 2002, Chief Financial
Officer and Chief Accounting Officer since January 2001. Ms. McGurk also serves
as Senior Vice President since January 2002 and Chief Accounting Officer of
Atlas America since January 2001. Ms. McGurk served as Chief Financial Officer
for Atlas America from January 2001 until February 2004. Ms. McGurk was a Vice
President of Resource America from 1992 until May 2004 and its Treasurer and
Chief Accounting Officer from 1989 until May 2004 when she resigned from
Resource America. Also, since 1995 Ms. McGurk has served as Vice President -
Finance of Resource Energy, Inc. Ms. McGurk received a Bachelor of Science
degree in Accounting from Ohio State University in 1978, and has been a
Certified Public Accountant since 1982. Ms. McGurk devotes approximately 80% of
her professional time to the business and affairs of our managing general
partner and Atlas America, and the remainder of her professional time to the
business and affairs of our managing general partner's affiliates.
MICHAEL L. STAINES. Senior Vice President, Secretary, and a Director since 1998.
Mr. Staines has been an Executive Vice President and Secretary of Atlas America
since 1998. Mr. Staines was a Senior Vice President of Resource America from
1989 until May 2004 when he resigned from Resource America. Mr. Staines was a
director of Resource America from 1989 to February 2000 and Secretary from 1989
to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP
since January 2001 and its Chief Operating Officer and a member of its Managing
Board since its formation in November 1999. Mr. Staines is a member of the Ohio
Oil and Gas Association and the Independent Oil and Gas Association of New York.
Mr. Staines received a Bachelor of Science degree from Cornell University in
1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines
devotes approximately 5% of his professional time to the business and affairs of
our managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of our managing general partner's
affiliates, including Atlas Pipeline Partners GP.
MICHAEL G. HARTZELL. Vice President - Land Administration since September 2001.
Mr. Hartzell has been Vice President - Land Administration of Atlas America
since January 2002, and before that served as Senior Land Coordinator from
January 1999 to January 2002. Mr. Hartzell has been with our managing general
partner and its affiliates since 1980 when he began his career as a land
department representative. Mr. Hartzell manages all Land Department functions.
Mr. Hartzell serves on the Environmental Committee of the Independent Oil and
Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr.
Hartzell devotes approximately 100% of his professional time to the business and
affairs of our managing general partner and Atlas America.
DONALD R. LAUGHLIN. Vice President - Drilling and Production since September
2001. Mr. Laughlin also serves as Vice President - Drilling and Production for
Atlas America since January 2002, and before that served as Senior Drilling
Engineer since May 2001 when he joined Atlas America. Mr. Laughlin has over
thirty years of experience as a petroleum engineer in the Appalachian Basin,
having been employed by Columbia Gas Transmission Corporation from October 1995
to May 2001 as a senior gas storage engineer and team leader, Cabot Oil & Gas
Corporation from 1989 to 1995 as Manager of Drilling Operations and Technical
Services, Doran & Associates, Inc. (an industrial engineering firm) from 1977
until 1989 as Vice President--Operations, and Columbia Gas from 1970 to 1977 as
Drilling Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum
Engineering degree from the University of Pittsburgh in 1970. He is a member of
the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of
his professional time to the business and affairs of our managing general
partner and Atlas America.
32
MARCI F. BLEICHMAR. Vice President of Marketing since February 2001. Ms.
Bleichmar also serves as Vice President of Marketing for Atlas America since
February 2001 and was with Resource America from February 2001 until May 2004
when she resigned from Resource America. From March 2000 until February 2001,
Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a
mutual fund manager), and from March 1998 until March 2000, she was an account
executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms.
Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms.
Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in
1992. Ms. Bleichmar devotes approximately 100% of her professional time to the
business and affairs of our managing general partner and Atlas America.
KAREN A. BLACK. Vice President - Partnership Administration since February 2003.
Ms. Black is also Vice President and Financial and Operations Principal of
Anthem Securities since October 2002. Ms. Black joined our managing general
partner and Atlas America in July 2000 and served as manager of production,
revenue and partnership accounting from July 2000 through October 2001, after
which she served as manager and financial analyst until her appointment as Vice
President - Partnership Administration. Before joining our managing general
partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as
controller from April 1997 through June 2000. Ms. Black was employed as a tax
accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997.
Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh,
Johnstown in 1982. Ms. Black devotes approximately 50% of her professional time
to the business and affairs of our managing general partner and Atlas America,
and the remainder of her professional time to the business and affairs of Anthem
Securities.
SHERWOOD S. LUTZ. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined
Viking Resources, which was purchased by Resource America in 1999 as senior
geologist. Since 1999 Mr. Lutz has been a senior geologist for our managing
general partner and Atlas America. Mr. Lutz received his Bachelor of Science
degree in Geological Sciences from the Pennsylvania State University in 1973.
Mr. Lutz is a certified petroleum geologist with the American Association of
Petroleum Geologists as well as a licensed professional geologist in
Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to
the business and affairs of our managing general partner and Atlas America.
MICHAEL W. BRECKO. Director of Energy Sales since November 2002. Mr. Brecko has
over 16 years of natural gas marketing experience in the oil and natural gas
industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University
with a Bachelor of Science degree in Civil Engineering. His career in natural
gas marketing began when he joined Equitable Gas Company, a local distribution
company, as a marketing representative in the commercial/ industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a
subsidiary of Orange and Rockland Utilities, as regional marketing manager from
August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr.
Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and
natural gas producer, as an account executive and he was promoted in August 1998
to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a
multi-energy sourced company, as a regional account manager before joining Atlas
America in 2002. Mr. Brecko devotes approximately 100% of his professional time
to the business and affairs of our managing general partner and Atlas America.
33
JUSTIN T. ATKINSON. Director of Due Diligence since February 2003. Mr. Atkinson
also serves as President of Anthem Securities since February 2004 and as Chief
Compliance Officer since October 2002. Before that Mr. Atkinson served as
assistant compliance officer of Anthem Securities from December 2001 until
October 2002 and Vice President from October 2002 until February 2004. Before
his employment with our managing general partner, Mr. Atkinson was a manager of
investor and broker/dealer relations with Viking Resources Corporation from 1996
until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business
Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson
devotes approximately 25% of his professional time to the business and affairs
of our managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of Anthem Securities.
WINIFRED C. LONCAR, Director of Investor Services since February 2003. Ms.
Loncar previously held the position of manager of investor services from the
inception of the investor service department in 1990 to February 2003. Before
that she was executive secretary to our managing general partner. Ms. Loncar
received a Bachelor of Science degree in Business from Point Park University in
1998. Ms. Loncar devotes approximately 100% of her professional time to the
business and affairs of our managing general partner and Atlas America.
CODE OF BUSINESS CONDUCT AND ETHICS. Because we do not directly employ any
persons, our managing general partner has determined that we will rely on a Code
of Business Conduct and Ethics adopted by Atlas America, Inc. that applies to
the principal executive officer, principal financial officer and principal
accounting officer of our managing general partner, as well as to persons
performing services for our managing general partner generally. You may obtain a
copy of this code of ethics by sending a request to our managing general partner
at Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania 15108.
ORGANIZATIONAL CHARTS. As discussed in "Managing General Partner," above,
Resource America has advised our managing general partner that on or before June
30, 2005, it intends to distribute all of its remaining shares of common stock
in Atlas America to its common stockholders. In addition, Resource America has
advised our managing general partner that the following corporate transactions,
among others, will occur before the distribution of the Atlas America stock is
made by Resource America:
o Atlas Energy Group, Inc., the driller and operator in Ohio and a
wholly-owned subsidiary of AIC, Inc., will be acquired by merger by
Atlas America. Atlas Energy Group will then cease to exist and its
subsidiary AED Investments, Inc. will become a direct wholly-owned
subsidiary of Atlas America, and Atlas America will assume Atlas
Energy Group's business as driller and operator in Ohio; and
o Atlas Energy Holdings, Inc., a holding company which is wholly-owned
by Resource America, will be merged into Resource America and Atlas
Energy Holdings will cease to exist.
However, the timing of the distribution of Atlas America stock by Resource
America and the mergers and other corporate transactions described above are
within Resource America's sole discretion and may not happen at the contemplated
times.
Set forth below are two organizational charts. The first chart depicts the
current relationships among Atlas Resources, which is our managing general
partner, and its affiliated entities, and delineates the current ownership of
each of the entities before the mergers and other corporate actions described
above occur. The second chart provides the same information concerning Atlas
Resources and its affiliated entities, but will apply only after all of the
mergers and other corporate actions discussed above have occurred, which
Resource America has advised our managing general partner it expects will be on
or before June 30, 2005.
34
ORGANIZATION CHART NO. 1: ATLAS RESOURCES, INC. AND ITS AFFILIATED ENTITIES BEFORE THE CORPORATE TRANSACTIONS
DESCRIBED IN " - ORGANIZATIONAL CHARTS," ABOVE.
+-----------------------------------------------------+
| Resource America, Inc. |
| Owns 100% of AEHI |
+--------------------------+--------------------------+
|
+--------------------------+--------------------------+
| Atlas Energy Holdings, Inc. ("AEHI") |
| Owns 100% of AAI (DE) |
+--------------------------+--------------------------+
|
+--------------------------+--------------------------+
| Atlas America, Inc. (Delaware) |
| ("AAI (DE)") |
| Owns 100% of the five |
| subsidiaries listed below. |
+--------------------------+--------------------------+
|
+-----------------+--------------------------+----------+---------------------------+-------------------------+
| | | | |
+--------+------+ +----+--------------+ +-----+-----------------------+ +---------+---------+ +-----------+---------+
| Viking | | AIC, Inc. | | Atlas America, Inc. | | Resource Energy, | | Atlas Noble |
| Resources | | Owns 100% of the | | (Pennsylvania) | | Inc. | | Corporation |
| Corporation | | five subsidiaries | | | | | | |
| | | listed below. | | | | | | |
+---------------+ +--+----------------+ +-----------------------------+ +-------------------+ +---------------------+
|
+-------------+-------------+--------------------------+-----------------------+------------------------------+
| | | | |
+----------+----------------+ +-----+----------+ +----------+---------+ +-------+-------------+ +----------+-------+
| Atlas Resources, Inc., | | Atlas Energy | | Pennsylvania | | Anthem Securities, | | Atlas Energy |
| Owns 100% of ARD and | | Corporation | | Industrial Energy, | | Inc. registered | | Group, Inc. Owns |
| serves as our managing | | | | Inc. | | broker/dealer and | | 100% of AED |
| general partner | | | | | | dealer-manager | | |
+----------+----------------+ +----------------+ +--------------------+ +---------------------+ +----------+-------+
| |
+----------+---------+ +-------------+-------+
| ARD Investments, | | AED Investments, |
| Inc. ("ARD") | | Inc. ("AED") |
+--------------------+ +---------------------+
35
ORGANIZATIONAL CHART NO. 2: ATLAS RESOURCES, INC. AND ITS AFFILIATED ENTITIES AFTER THE CORPORATE TRANSACTIONS
DESCRIBED IN " - ORGANIZATIONAL CHARTS," ABOVE.
+-----------------------------------------------------+
| Atlas America, Inc. (Delaware) Owns 100% of |
| the six subsidiaries listed below |
+--------------------------+---------------------------+
|
+------------------------+---------------------+-------------+-----+------------------------+--------------------+
| | | | | |
+----+--------------+ +------+-----------+ +-------+------------+ +---+--------------+ +------+--------+ +--------+-------+
| Viking | | AIC, Inc. | | Atlas America, Inc.| | Resource | | Atlas Noble | |AED Investments,|
| Resources | | Owns 100% of | | (Pennsylvania) | | Energy, Inc. | | Corporation | | Inc. |
| Corporation | | the four | | | | | | | | |
| | | subsidiaries | | | | | | | | |
| | | listed below. | | | | | | | | |
+-------------------+ +--------+---------+ +--------------------+ +------------------+ +---------------+ +----------------+
|
+------------------+-----------------+-----------------------------------+---------------------------------+
| | | |
+------------+--------------+ +-----------------+------------------+ +------------+--------------+ +--------------+--------+
| Atlas Resources, Inc. | | Atlas Energy Corporation | | Pennsylvania | | Anthem Securities, |
| Owns 100% of ARD and | | | | Industrial Energy, Inc. | | Inc., registered |
| serves as our managing | | | | | | broker/dealer and |
| general partner | | | | | | dealer-manager |
+------------+--------------+ +------------------------------------+ +---------------------------+ +-----------------------+
|
+------------+---------------+
| ARD Investments, Inc. |
| ("ARD") |
+----------------------------+
ITEM 6. EXECUTIVE COMPENSATION.
We have no employees and rely on the employees of our managing general partner
and its affiliates for all of our services. No officer or director of our
managing general partner will receive any direct remuneration or other
compensation from us. These persons will receive compensation solely from
affiliated companies of our managing general partner.
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
OIL AND GAS REVENUES. Our managing general partner is allocated 35% of our
natural gas and oil revenues in return for having paid and contributed services
towards organization and offering costs equal to 15% of our subscriptions,
paying 76% of the tangible costs of our wells and contributing all of the leases
covering each of our prospects on which one well is situated, for a total
capital contribution of $16,007,100.
During the period ended December 31, 2004, our managing general partner received
no distributions.
LEASES. During the period ended December 31, 2004, our managing general partner
contributed undeveloped prospects (leases) to us to drill 157.4 net wells, and
received a credit in the amount of $1,033,000. Our managing general partner does
not anticipate entering into any further lease transactions with us.
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 will be proportionately reduced if we acquire less
than 100% of the working interest in a well. Our managing general partner
received $6,600 in these fees for the period ended December 31, 2004.
36
DIRECT COSTS. Our managing general partner and its affiliates will be reimbursed
for all direct costs expended on our behalf whether acting as managing general
partner or operator. For the period ended December 31, 2004, we reimbursed the
managing general partner $13,900 for these direct costs.
DRILLING CONTRACTS. We entered into a drilling and operating agreement with our
managing general partner after our initial and final closing dates to drill and
complete 157.4 net wells. The total amount received by our managing general
partner from the subscription proceeds was $31,531,000. This was paid by our
participants for their share of the costs of drilling and completing the wells,
including the wells which were prepaid in 2004, but the drilling of which was to
begin on or before March 30, 2005. We have not entered into any further drilling
transactions to the date of this filing, and none are anticipated by us for
future periods.
PER WELL CHARGES. Our managing general partner, as operator, is reimbursed at
actual cost for all direct expenses incurred on our behalf as set forth above in
"Direct Costs" 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 annual adjustments for inflation. During the period ended December
31, 2004, our managing general partner received $24,100 for well supervision
fees.
GATHERING FEES. We pay a gathering fee to our managing general partner at a
competitive rate for each mcf transported. For the period ended December 31,
2004, the amount paid was $34,500. Of this amount, 100% was paid by our managing
general partner to Atlas Pipeline Partners and nothing was paid to unaffiliated
third-parties.
DEALER-MANAGER FEES. As part of the offering of our Units, our managing general
partner's affiliate, Anthem Securities, Inc., serving as dealer-manager,
received a 3.5% dealer-manager fee, an 8% sales commission, a 1.5%
nonaccountable marketing expense fee, and a .5% nonaccountable due diligence fee
in the aggregate amount of $4,082,500. The dealer-manager will receive no
further compensation from us. Of this amount, 96.5% was paid by Anthem
Securities to third-party broker/dealers who participated in the offering of our
Units.
ORGANIZATION AND OFFERING COSTS. During the period ended December 31, 2004, our
managing general partner paid and contributed services for organization and
offering costs in the amount of $647,200.
OTHER COMPENSATION. If our managing general partner makes a loan to us it may
receive a competitive rate of interest. If our managing general partner provides
equipment, supplies and other services to us, then it may do so at competitive
industry rates. For the period ended December 31, 2004, no advances were made to
us by our managing general partner.
ITEM 8. LEGAL PROCEEDINGS.
None
37
ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
Currently, there is no established public trading market for our Units.
As of December 31, 2004, there were no outstanding options or warrants to
purchase, or securities convertible into Units. In addition, as of December 31,
2004, there were no Units that could be sold pursuant to Rule 144 under the
Securities Act or that we have agreed to register under the Securities Act for
sale by our participants and there were no Units that were being, or were
publicly proposed to be, publicly offered by us.
As of December 31, 2004, there were 634 holders of records of the Units.
Our managing general partner reviews our accounts monthly to determine whether
cash distributions are appropriate and the amount to be distributed to our
managing general partner and our participants, if any. Cash distributions to our
managing general partner may only be made in conjunction with distributions to
our participants and only out of funds properly allocated to our managing
general partner's account. We distribute those funds which our managing general
partner determines are not necessary for us to retain, taking into account our
managing general partner's subordination obligation as described in "Description
of Registrant's Securities to be Registered - Distributions and Subordination."
We will not advance or borrow funds for purposes of distributions to our
participants 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. We will distribute funds to our
participants that our managing general partner, in its sole discretion, does not
believe are necessary for us to retain. Distributions may be reduced or deferred
to the extent our revenues are used for any of the following:
o repayment of borrowings;
o cost overruns;
o remedial work to improve a well's producing capability;
o our direct costs;
o general and administrative expenses of our managing general partner;
o reserves, including a reserve for the estimated costs of eventually
plugging and abandoning the wells; or
o our indemnification of our managing general partner and its affiliates
for losses or liabilities incurred in connection with our activities.
The determination of our revenues and costs will be made in accordance with
generally accepted accounting principles, consistently applied. During the
period ended December 31, 2004, we made no cash distributions to our
participants or our manager partner.
38
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES.
We sold 1,265.38 Units to 634 investors in a private placement offering
beginning June 1, 2004 and ending August 31, 2004. Anthem Securities, Inc., an
affiliate of our managing general partner, served as the dealer-manager of the
offering and received the compensation set forth in Item 7 "Certain
Relationships and Related Transactions - Dealer-Manager Fees." Our net proceeds
from the sale of the Units were $31,531,000.
We relied on the exemption from registration provided by Rule 506 under
Regulation D and Section 4(2) of the Securities Act in connection with the
offering. The Units were offered and sold to a limited number of persons who had
the sophistication to understand the merits and risks of the investment and who
had the financial ability to bear those risks. The Units were sold to persons
who were accredited investors, as that term is defined in Regulation D (17 CFR
230.501(a)), or to persons who our managing general partner reasonably believed
immediately before sale, either individually or together with their purchaser
representatives, had such knowledge and experience in financial matters that
they were capable of evaluating the merits and risks of an investment in us. Of
our 634 participants, all were reasonably believed by our managing general
partner to be accredited investors at the time of sale.
ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED.
GENERAL. The rights and obligations of the holders of the Units (i.e., our
participants) are governed by the partnership agreement. Units mean both limited
partner Units and investor general partner Units. The investor general partner
Units will be automatically converted into limited partner Units after all of
our wells have been drilled and completed. The following is a summary of some of
the provisions of the partnership agreement related to the rights and
obligations associated with the Units and is qualified in its entirety by the
full text of the partnership agreement.
We were formed under the Delaware Revised Uniform Limited Partnership Act and
are qualified to transact business in the jurisdictions where our wells are
located. Our managing general partner is Atlas Resource, Inc., which has
exclusive management control over all aspects of our business. In the course of
its management, our managing general partner may, in its sole discretion, employ
any persons, including its affiliates, as it deems necessary for our efficient
operation.
LIABILITY OF PARTICIPANTS FOR FURTHER CALLS AND CONVERSION. We will be governed
by the Delaware Revised Uniform Limited Partnership Act. If a participant
invested in us as a limited partner, then generally the participant will not be
liable to third-parties for our obligations unless the participant:
o also invested in us as an investor general partner;
o takes part in the control of our business in addition to the exercise
of a participant's rights and powers as a limited partner; or
o fails to make a required capital contribution to the extent of the
required capital contribution.
In addition, a limited partner participant may be required to return any
distribution received if the participant knew at the time the distribution was
made that it was improper because it rendered us insolvent.
39
If the participant invested in us as an investor general partner for the tax
benefits instead of as a limited partner, then his Units will be automatically
converted by our managing general partner to limited partner Units after all of
our wells have been drilled and completed. See Item 1 "Business." Currently, the
conversion has not occurred.
After the investor general partner Units are converted to limited partner Units,
which is a nontaxable event, the participant will have the lesser liability of a
limited partner under Delaware law for obligations and liabilities arising in us
after the conversion, subject to the exceptions described above. However, an
investor general partner will continue to have the responsibilities of a general
partner for our liabilities and obligations incurred before the effective date
of the conversion. For example, an investor general partner might become liable
for any liabilities we incurred in excess of his subscription amount during the
time we engaged in drilling activities and for environmental claims that arose
during drilling activities, but were not discovered until after conversion. This
could result in the former investor general partner being required to make
payments, in addition to his original investment, in amounts that are impossible
to predict because of their uncertain nature.
DISTRIBUTIONS AND SUBORDINATION. Subject to our managing general partner's
subordination obligation as described below, our managing general partner and
our participants share in all of our production revenues in the same percentage
as their respective capital contribution bears to the total partnership capital
contributions, except that our managing general partner receives an additional
7% of our revenues. However, our managing general partner's total revenue share
may not exceed 35% of our revenues regardless of the amount of its capital
contributions. As of December 31, 2004, our managing general partner received
35% of our production revenues and our participants received 65% of our
production revenues. See the partnership agreement for special provisions
regarding the allocation between our managing general partner and our
participants for equipment proceeds, lease proceeds and interest.
However, our partnership agreement is structured to provide our participants
with cash distributions equal to a minimum of 10% per Unit, based on $25,000 per
Unit regardless of the actual subscription price paid by any participant for a
Unit, in each of the first five 12-month periods beginning with our first cash
distributions of revenues from operations. To help achieve this investment
feature, under our partnership agreement our managing general partner will
subordinate up to 50% of its share (after deducting a 1% broker/dealer
participation) of our partnership net production revenues during this
subordination period, which is up to 17% of our total partnership net production
revenues. The term "partnership net production revenues" means our gross
revenues from the sale of our natural gas and oil production from our wells
after deduction of the related operating costs, direct costs, administrative
costs, and all other costs not specifically allocated in the partnership
agreement. If our wells produce only small natural gas and oil volumes, and/or
natural gas and oil prices decrease, then even with subordination a participant
may not receive the 10% return of capital for each of the first five years as
described above, or a return of his capital during our term, because the
subordination is not a guarantee.
Our 60-month subordination period began with our first cash distribution of
revenues from operations on February 5, 2005. However, no subordination
distributions will be required until our first cash distribution after
substantially all of our wells are drilled, completed, and begin producing into
a sales line. Subordination distributions will be determined by debiting or
crediting current period partnership revenues to our managing general partner as
may be necessary to provide the distributions to our participants. At any time
during the subordination period our managing general partner is entitled to an
additional share of our revenues to recoup previous subordination distributions
to the extent cash distributions from us exceed the 10% return described above.
The specific formula is set forth in Section 5.01(b)(4)(a) of our partnership
agreement.
40
Our managing general partner will review our accounts at least monthly to
determine whether cash distributions are appropriate and the amount to be
distributed, if any, taking into account its subordination obligation discussed
above.
PARTICIPANT ALLOCATIONS. The participants' share as a group of our revenues,
gains, income, costs, expenses, losses, and other charges and liabilities
generally are charged and credited among our participants in accordance with
their respective number of Units, based on $25,000 per Unit regardless of the
actual subscription price paid by any participant for the Units. These
allocations also take into account any investor general partner's status as a
defaulting investor general partner.
Certain participants, however, paid a reduced amount for their Units. Thus,
intangible drilling costs and a participant's share of the equipment costs of
drilling and completing our wells are charged among our participants in
accordance with the respective subscription price they paid for their Units,
rather than their respective number of Units.
TERM, DISSOLUTION AND DISTRIBUTIONS ON LIQUIDATION. We will continue in
existence for 50 years unless we are terminated earlier by a final terminating
event as described below, or an event which causes the dissolution of a limited
partnership under the Delaware Revised Uniform Limited Partnership Act. However,
if we terminate on an event which causes a dissolution under state law and it is
not a final terminating event, then a successor limited partnership will
automatically be formed. Thus, only on a final terminating event will we be
liquidated. A final terminating event is any of the following:
o the election to terminate us by our managing general partner or the
affirmative vote of our participants whose Units equal a majority of
our total Units;
o our termination under Section 708(b)(1)(A) of the Internal Revenue
Code because no part of our business is being carried on; or
o we cease to be a going concern.
On our liquidation a participant will receive his capital interest in us.
Generally, this means an undivided interest in our assets, after payments to our
creditors, in the ratio the participant's capital account bears to all of the
capital accounts in us until all capital accounts have been reduced to zero.
Thereafter, the participant's capital interest in our remaining assets will
equal the participant's interest in our related revenues.
Any in-kind property distributions to a participant from us must be made to a
liquidating trust or similar entity, unless the participant affirmatively
consents to receive an in-kind property distribution after being told the risks
associated with the direct ownership of our natural gas and oil properties or
there are alternative arrangements in place which assure that the participant
will not be responsible for the operation or disposition of our natural gas and
oil properties. If our managing general partner has not received a participant's
written consent to the in-kind distribution within 30 days after it is mailed,
then it will be presumed that the participant did not consent. Our managing
general partner may then sell the asset at the best price reasonably obtainable
from an independent third-party, or to itself or its affiliates at fair market
value as determined by an independent expert selected by our managing general
partner. Also, if we are liquidated, our managing general partner will be repaid
for any debts owed it by us before there are any payments to our participants.
41
TRANSFERABILITY. Units may not be sold, assigned or otherwise transferred unless
certain conditions set forth in the partnership agreement are satisfied,
including:
o our managing general partner's written consent to the transfer;
o an opinion of counsel acceptable to our managing general partner that
the sale, assignment, pledge, hypothecation, or transfer of the Unit
does not require registration and qualification under the Securities
Act of 1933 and applicable state securities laws; and
o a determination under the tax laws that a sale, assignment, exchange,
or transfer of the Unit would not, in the opinion of our counsel,
result in our termination for tax purposes or our being treated as a
"publicly-traded" partnership for tax purposes.
Also, under the partnership agreement transfers are subject to the
following limitations:
o except as provided by operation of law, we will recognize the transfer
of only one or more whole Units unless the participant transferor owns
less than a whole unit, in which case the entire fractional interest
must be transferred;
o the costs and expenses associated with the transfer must be paid by
the participant transferring the unit;
o the form of transfer must be in a form satisfactory to the managing
general partner; and
o the terms of the transfer must not contravene those of the partnership
agreement.
A transfer of a Unit will not relieve the participant transferor of
responsibility for any obligations related to his Units under the partnership
agreement. Also, the transfer does not grant rights under the partnership
agreement, as among the transferees, to more than one party unanimously
designated by the transferees to our managing general partner. Further, the
transfer of a Unit does not require an accounting by our managing general
partner. Any transfer when the assignee of the Unit does not become a
substituted partner as described below will be effective as of midnight of the
last day of the calendar month in which it is made or, at our managing general
partner's election, 7:00 A.M. of the following day. Finally, a sale of a
participant's Units could create adverse tax and economic consequences for the
participant. The sale or exchange of all or part of the Units held for more than
12 months generally will result in recognition of long-term capital gain or
loss. However, previous deductions by the participant for depreciation,
depletion and IDCs may be recaptured as ordinary income rather than capital gain
regardless of how long the participant owned the Units. If the Units are held
for 12 months or less, then the gain or loss generally will be short-term gain
or loss. The participant's pro rata share of our liabilities, if any, as of the
date of the sale or exchange must be included in the amount realized by the
participant. Thus, the gain recognized by the participant may result in a tax
liability greater than the cash proceeds, if any, received by the participant
from the sale or other taxable disposition of the Units.
42
Under the partnership agreement an assignee (transferee) of a Unit may become a
substituted partner only on meeting certain further conditions. The conditions
to become a substitute partner are as follows:
o the assignor gives the assignee the right;
o our managing general partner consents to the substitution;
o the assignee pays all costs and expenses incurred in connection with
the substitution; and
o the assignee executes and delivers the instruments necessary to
establish that a legal transfer has taken place and to confirm his or
her agreement to be bound by all terms and provisions of the
partnership agreement.
A substitute partner is entitled to all of the rights of full ownership of the
assigned Units, including the right to vote. We will amend our records at least
once each calendar quarter to effect the substitution of substituted partners.
PRESENTMENT FEATURE. Beginning in 2009 a participant may present his Units to
our managing general partner for purchase. However, a participant is not
required to offer his Units to our managing general partner, and may receive a
greater return if the Units are retained.
Our managing general partner has no obligation and does not intend to establish
a reserve to satisfy the presentment obligation and may immediately suspend its
purchase obligation by notice to our participants if it determines, in its sole
discretion, that it does not have the necessary cash flow or cannot arrange
financing or other consideration for this purpose on terms it deems reasonable.
Our managing general partner will not purchase less than one Unit unless the
fractional unit represents the entire interest, nor more than 10% of the Units
in any calendar year. If fewer than all Units presented at any time are to be
purchased, then the Units to be purchased will be selected by lot. Our managing
general partner may not waive the limit on its purchasing more than 10% of the
Units in any calendar year.
Our managing general partner's obligation to purchase the Units presented may be
discharged for its benefit by a third-party or an affiliate of our managing
general partner. The Unit will be transferred to the party who pays for it,
along with the delivery of an executed assignment. The presentment must be
within 120 days of the partnership reserve report discussed below, and in
accordance with Treas. Reg. ss.1.7704-1(f) the purchase may not be made by our
managing general partner until at least 60 calendar days after written notice of
the participant's intent to present the Unit.
The amount of the presentment price attributable to our natural gas and oil
reserves will be determined based on the last reserve report. Beginning in 2006
our managing general partner will prepare an annual reserve report of our
natural gas and oil proved reserves which will be reviewed by an independent
expert every other year beginning in 2007.
43
The presentment will not be considered effective until the following conditions
are satisfied:
o the participant receives information concerning the present worth of
our future net revenues attributable to our proved reserves;
o the participant agrees to the presentment price as calculated below;
and
o payment has been made in cash or other consideration as agreed to
between our managing general partner and the participant.
The presentment price to a participant will be based on his share of our net
assets and liabilities as described below, based on the ratio that his number of
Units bears to the total number of our Units. The presentment price will include
the sum of the following partnership items:
o an amount based on 70% of the present worth of future net revenues
from the proved reserves determined as described above;
o cash on hand;
o prepaid expenses and accounts receivable, less a reasonable amount for
doubtful accounts; and
o the estimated market value of all assets not separately specified
above, determined in accordance with standard industry valuation
procedures.
There will be deducted from the foregoing sum the following partnership items:
o an amount equal to all debts, obligations, and other liabilities,
including accrued expenses; and
o any distributions made to the participant between the date of the
request and the actual payment. However, if any cash distributed was
derived from the sale, after the presentment request, of oil, natural
gas, or a producing property, for purposes of determining the
reduction of the presentment price the distributions will be
discounted at the same rate used to take into account the risk factors
employed to determine the present worth of our proved reserves.
The amount may be further adjusted by our managing general partner for estimated
changes from the date of the reserve report to the date of payment of the
presentment price because of the various considerations described in the
partnership agreement.
VOTING RIGHTS AND AMENDMENTS. Other than as set forth below, a participant
generally will not be entitled to vote on any partnership matters at any
meeting. However, at any time participants whose Units equal 10% or more of the
total Units may call a meeting to vote, or vote without a meeting, on the
matters set forth below without the concurrence of our managing general partner.
On the matters being voted on a participant is entitled to one vote per Unit or
if a fractional Unit that fraction of one vote equal to the fractional interest
in the Unit. Participants whose Units equal a majority of the total Units may
vote to:
44
o dissolve us;
o remove our managing general partner and elect a new managing general
partner;
o elect a new managing general partner if our managing general partner
elects to withdraw from the partnership;
o remove the operator and elect a new operator;
o approve or disapprove the sale of all or substantially all of our
assets;
o cancel any contract for services with our managing general partner,
the operator, or their affiliates, which is not otherwise described in
the private placement memorandum or the partnership agreement without
penalty on 60 days notice; and
o amend the partnership agreement; provided however, any amendment may
not:
o without the approval of our participants or our managing general
partner, increase the duties or liabilities of the participants or our
managing general partner or increase or decrease the profits or losses
or required capital contribution of our participants or our managing
general partner; or
o without the unanimous approval of our participants, affect the
classification of our income and loss for federal income tax purposes.
Although our managing general partner and its officers, directors, and
affiliates could have voted on certain issues as a participant if they had
purchased Units, they did not purchase any Units. In addition to amendments by
our participants as described above, amendments to the partnership agreement may
be proposed in writing by our managing general partner and adopted with the
consent of participants whose Units equal a majority of the total Units. The
partnership agreement may also be amended by our managing general partner
without the consent of our participants for certain limited purposes.
BOOKS AND RECORDS. Our managing general partner is required to keep true and
accurate books of account of all of our financial activities in accordance with
generally accepted accounting principles. A participant is permitted access to
all of our records other than a list of our other participants. A participant
may inspect and copy any of the records, other than a list of our participants,
at any reasonable time after giving adequate notice to our managing general
partner. However, our managing general partner may keep logs, well reports, and
other drilling and operating data confidential for reasonable periods of time.
45
RESTRICTIONS ON ROLL-UP TRANSACTIONS. In connection with any proposed
transaction which is considered to be a "Roll-up Transaction" involving us and
the issuance of securities of an entity (a "Roll-up Entity") that would be
created or would survive after the successful completion of the Roll-up
Transaction, an appraisal of all of our natural gas and oil properties must be
obtained from a competent independent appraiser. Our properties must be
appraised on a consistent basis, and the appraisal must be based on the
evaluation of all relevant information and must indicate the value of our
properties as of a date immediately before the announcement of the proposed
Roll-up Transaction. The appraisal must assume an orderly liquidation of our
properties over a 12-month period. The terms of the engagement of the
independent appraiser must clearly state that the engagement is for the benefit
of us and our participants. A summary of the appraisal, indicating all of the
material assumptions underlying the appraisal, must be included in a report to
our participants in connection with the proposed Roll-up Transaction. A "Roll-up
Transaction" is transaction involving our acquisition, merger, conversion or
consolidation, directly or indirectly, and the issuance of securities of a
Roll-up Entity. This term does not include:
o a transaction involving our securities that have been listed on a
national securities exchange or included for quotation on Nasdaq
National Market System for at least 12 months; or
o a transaction involving only our conversion to corporate, trust, or
association form if, as a consequence of the transaction, there will
be no significant adverse change in any of the following: voting
rights; the term of our existence; compensation to our managing
general partner; or our investment objectives.
In connection with a proposed Roll-up Transaction, the person sponsoring the
Roll-up Transaction must offer to our participants who vote "no" on the proposal
the choice of:
o accepting the securities of a Roll-up Entity offered in the proposed
Roll-up Transaction; or
o one of the following:
o remaining as participants in us and preserving their interests in us
on the same terms and conditions as existed previously, or
o receiving cash in an amount equal to the participant's pro rata share
of the appraised value of our net assets.
We are prohibited from participating in any proposed Roll-Up Transaction:
o which would result in the diminishment of any participant's voting
rights under the Roll-up Entity's chartering agreement;
o in which the democracy rights of our participants in the Roll-up
Entity would be less than those provided for under ss.ss.4.03(c)(1)
and 4.03(c)(2) of the partnership agreement or, if the Roll-up Entity
is a corporation, then the democracy rights of our participants must
correspond to the democracy rights provided for our participants in
the partnership agreement to the greatest extent possible;
46
o which includes provisions that would operate to materially impede or
frustrate the accumulation of shares by any purchaser of the
securities of the Roll-up Entity, except to the minimum extent
necessary to preserve the tax status of the Roll-up Entity;
o in which our participants' rights of access to the records of the
Roll-up Entity would be less than those provided for under
ss.ss.4.03(b)(5) and 4.03(b)(6) of the partnership agreement;
o in which any of the costs of the transaction would be borne by us if
our participants whose Units equal a majority of the total Units do
not vote to approve the proposed Roll-Up Transaction; and
o unless the Roll-up Transaction is approved by our participants whose
Units equal a majority of the total Units.
We currently have no plans to enter into a Roll-Up Transaction.
WITHDRAWAL OF MANAGING GENERAL PARTNER. After 10 years our managing general
partner may voluntarily withdraw as our managing general partner for whatever
reason by giving 120 days' written notice to our participants. Although our
withdrawing managing general partner is not required to provide a substitute
managing general partner, a new managing general partner may be substituted by
the affirmative vote of our participants whose Units equal a majority of the
total Units. If our participants, however, choose for us not to continue in
existence and do not select a substitute managing general partner, then we would
terminate and dissolve which could result in adverse tax and other consequences
to our participants.
Also, subject to a required participation of not less than 1% of our revenues,
our managing general partner may withdraw a property interest from us in the
form of a working interest in our wells equal to or less than its revenue
interest in us without the consent of our participants.
ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Under the terms of the partnership agreement our managing general partner, the
operator, and their affiliates have limited their liability to us and our
participants for any loss suffered by us or the participants which arises out of
any action or inaction on their part if:
o they determined in good faith that the course of conduct was in our
best interest;
o they were acting on behalf of, or performing services for, us; and
o their course of conduct did not constitute negligence or misconduct.
In addition, the partnership agreement provides for indemnification of our
managing general partner, the operator, and their affiliates by us against any
losses, judgments, liabilities, expenses, and amounts paid in settlement of any
claims sustained by them in connection with us provided that they meet the
standards set forth above. However, there is a more restrictive standard for
indemnification for losses arising from or out of an alleged violation of
federal or state securities laws. Also, to the extent that any indemnification
provision in the partnership agreement purports to include indemnification for
liabilities arising under the Securities Act of 1933, as amended, you should be
aware that, in the SEC's opinion, this indemnification is contrary to public
policy and therefore unenforceable.
47
Payments arising from the indemnification or agreement to hold harmless are
recoverable only out of our tangible net assets, revenues, and insurance
proceeds. Still, use of our funds or assets for indemnification of our managing
general partner, the operator or an affiliate would reduce amounts available for
our operations or for distribution to our participants.
We may not pay the cost of the portion of any insurance that insures our
managing general partner, the operator, or an affiliate against any liability
for which they cannot be indemnified. However, our funds can be advanced to them
for legal expenses and other costs incurred in any legal action for which
indemnification is being sought if we have adequate funds available and certain
conditions in the partnership agreement are met.
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS
PAGE
Balance Sheet ............................................................. 49
Statement of Operations ................................................... 50
Statements of Changes in Partners' Capital Accounts ....................... 51
Statement of Cash Flows ................................................... 52
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
48
ITEM 15. FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
-------------------------------------------------------
To the Partners of
ATLAS AMERICA SERIES 25-2004(B) L.P.
A Delaware Limited Partnership
We have audited the accompanying balance sheet of Atlas America Series
25-2004(B) L.P. (a Delaware Limited Partnership) as of December 31, 2004, and
the related statements of operations, changes in partners' capital accounts and
cash flows for the period June 21, 2004 (date of formation) to December 31,
2004. 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 audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (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. The Partnership is not required to
have, nor were we engaged to perform an audit of its internal control over
financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Partnership's internal control over
financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Atlas America Series 25-2004(B)
L.P. as of December 31, 2004, and the results of its operations, changes in
partners' capital accounts and cash flows for the period June 21, 2004 (date of
formation) to December 31, 2004, in conformity with accounting principles
generally accepted in the United States of America.
/s/ Grant Thornton LLP
Cleveland, Ohio
April 8, 2005
49
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
BALANCE SHEET
DECEMBER 31, 2004
ASSETS
Current assets:
Cash and cash equivalents...................................... $ 100
Accounts receivable - affiliate ............................... 764,300
------------
Total current assets...................................... 764,400
Oil and gas properties, (successful efforts)................... 43,805,300
Less accumulated depletion and depreciation............... (630,200)
------------
43,175,100
------------
43,939,500
============
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accrued liabilities............................................ $ 2,800
------------
Total current liabilities................................ 2,800
Asset retirement obligation.................................... 997,000
Partners' capital:
Managing general partner.................................. 11,387,800
Other partners (1265.38 units) ........................... 31,551,900
------------
42,939,700
------------
$ 43,939,500
============
The accompanying notes are an integral part of this financial statement
50
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
STATEMENT OF OPERATIONS
FOR THE PERIOD JUNE 21, 2004 (DATE OF FORMATION)
THROUGH DECEMBER 31, 2004
REVENUES
Natural gas and oil sales..................................... $ 840,600
-------------
Total revenues........................................... 840,600
COST AND EXPENSES
Production expenses........................................... 69,700
Depletion and depreciation of oil and gas properties.......... 630,200
General and administrative expenses...........................
9,400
-------------
Total expenses........................................... 709,300
-------------
NET EARNINGS......................................... $ 131,300
=============
ALLOCATION OF NET EARNINGS:
Managing general partner................................... $ 110,400
=============
Other partners............................................. $ 20,900
=============
Net earnings per other partners unit..................... $ 17
=============
The accompanying notes are an integral part of this financial statement
51
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
STATEMENT OF CHANGES IN PARTNERS' CAPITAL ACCOUNTS
FOR THE PERIOD JUNE 21, 2004 (DATE OF FORMATION)
THROUGH DECEMBER 31, 2004
MANAGING
GENERAL OTHERS
PARTNER PARTNERS TOTAL
------------ ------------ ------------
BALANCE AT JUNE 21, 2004 ............................... $ - $ - $ -
Partners' capital contributions:
Cash .............................................. 100 31,531,000 31,531,100
Syndication and offering costs .................... 4,729,700 - 4,729,700
Tangible costs .................................... 10,244,300 - 10,244,300
Lease costs ....................................... 1,033,000 - 1,033,000
------------ ------------ ------------
16,007,100 31,531,000 47,538,100
Syndication and offering costs, immediately
charged to capital ................................... (4,729,700) - (4,729,700)
------------ ------------ ------------
Total capital contributions ....................... 11,277,400 31,531,000 42,808,400
Participation in revenues and expenses
Net production revenues ........................... 262,100 508,800 770,900
Depletion and depreciation ........................ (148,500) (481,700) (630,200)
General and administrative ........................ (3,200) (6,200) (9,400)
------------ ------------ ------------
Net earnings .................................. 110,400 20,900 131,300
------------ ------------ ------------
BALANCE AT DECEMBER 31, 2004 ........................... $ 11,387,800 $ 31,551,900 $ 42,939,700
============ ============ ============
The accompanying notes are an integral part of this financial statement
52
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
STATEMENT OF CASH FLOWS
FOR THE PERIOD JUNE 21, 2004 (DATE OF FORMATION)
THROUGH DECEMBER 31, 2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings ..................................................................... $ 131,300
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion and depreciation .................................................. 630,200
Increase in accounts receivable - affiliate ................................. (764,300)
Increase in accrued liabilities ............................................. 2,800
------------
Net cash provided by operating activities ............................... -
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas well drilling contracts paid to Managing General Partner ........ (31,531,000)
------------
Net cash used in investing activities ................................... (31,531,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Partners' capital contribution .............................................. 31,531,100
------------
Net cash provided by financing activities ............................... 31,531,100
------------
Net increase in cash and cash equivalents ............................... 100
Cash and cash equivalents at beginning of period ................................. -
------------
Cash and cash equivalents at end of period ....................................... $ 100
============
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
- --------------------------------------------------------------------
Assets contributed by Managing General Partner:
Tangible equipment/lease costs, included in oil and gas properties .......... $ 11,277,300
Syndication and offering costs .............................................. 4,729,700
Capitalized asset retirement costs .......................................... 997,000
------------
$ 17,004,100
============
The accompanying notes are an integral part of this financial statement
53
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 1 - NATURE OF OPERATIONS
Atlas America Series #25-2004 (B) L.P. (the "Partnership") is a Delaware Limited
Partnership which includes Atlas Resources, Inc. ("Atlas") of Pittsburgh,
Pennsylvania, as Managing General Partner and Operator, and subscribers to units
as either Limited Partners or Investor General Partners depending upon their
election. As of December 31, 2004, there were 634 investors who contributed
$31,531,000. Partnership was formed on June 21, 2004 to drill and operate gas
wells located primarily in Western Pennsylvania and Tennessee. Partnership
operations began at our first closing on June 21, 2004. Recoverability of the
cost of properties is dependent on the results of such development activities.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of significant accounting policies applied in the preparation of the
accompanying financial statements follows:
Basis of Accounting
- -------------------
The financial statements are prepared in accordance with accounting principles
generally accepted in the United States of America.
Cash and Cash Equivalents
- -------------------------
The partnership considers temporary investments with a maturity at the date of
acquisition of 90 days or less to be cash equivalents. Financial instruments,
which potentially subject the Partnership to concentrations of credit risk,
consist principally of periodic temporary investments of cash and cash
equivalents. The Partnership places its temporary cash investments in deposits
with high-quality financial institutions. At December 31, 2004, the Partnership
had $34,828 deposits at one bank of which none was over the insurance limit of
the Federal Deposit Insurance Corporation. No losses have been experienced on
such investments.
Impairment of Long Lived Assets
- -------------------------------
The Partnership reviews its long-lived assets for impairment whenever events or
circumstances indicated that the carrying amount of an asset may not be
recoverable. If it is determined that an asset's estimated future cash flows
will not be sufficient to recover its carrying amount, an impairment charge will
be recorded to reduce the carrying amount for that asset to its estimated fair
value.
54
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Oil and Gas Properties
- ----------------------
Oil and gas properties consist of the following:
AT DECEMBER 31,
2004
---------------
Capitalized costs of properties:
Proved properties................................................... $ 1,033,000
Wells and related equipment......................................... 42,772,300
---------------
43,805,300
Accumulated depreciation and depletion................................... (630,200)
---------------
$ 43,175,100
===============
The Partnership uses the successful effort method of accounting for oil and gas
producing activates. Costs to acquire mineral interests in oil and gas
properties and to drill and equip wells are capitalized. Costs of exploratory
wells which do not find proved reserves are expensed.
Upon the sale or retirement of a complete or partial unit of a proved property,
the cost is eliminated from the property accounts, and the resultant gain or
loss is reclassified to accumulated depletion.
Depreciation, Depletion and Amortization
- ----------------------------------------
The Partnership depletes proved gas and oil properties, which include intangible
drilling and development costs, tangible well equipment and leasehold costs, on
the unit-of-production method using the ratio of current production to the
estimated aggregate proved developed gas and oil reserves.
Use of Estimates
- ----------------
Preparation of the financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities as of the
date of the financial statements and the reported amounts of revenues and costs
and expenses during the reporting period. Actual results could differ from these
estimates.
55
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Asset Retirement Obligation
- ---------------------------
The Partnership follows Statement of Financial Accounting Standards No. 143
"Accounting for Asset Retirement Obligations" (SFAS No. 143) which requires the
Partnership to recognize an estimated liability for the plugging and abandonment
of its oil and gas wells. Under SFAS No. 143, the Partnership must currently
recognize a liability for future asset retirement obligations if a reasonable
estimate of the fair value of that liability can be made. The present values of
the expected asset retirement costs are capitalized as part of the carrying
amount of the long-lived asset. SFAS No. 143 requires the Partnership to
consider estimated salvage value in the calculation of depletion and
depreciation.
The estimated liability is based on the managing general partner's historical
experience in plugging and abandoning wells, estimated remaining lives of those
wells based on reserves estimates, external estimates as to the cost to plug and
abandon the wells in the future, and federal and state regulatory requirements.
The liability is discounted using an assumed credit-adjusted risk-free interest
rate. Revisions to the liability could occur due to changes in estimates of
plugging and abandonment costs or remaining lives of the wells, or if federal or
state regulators enact new plugging and abandonment requirements.
The Partnership has no assets legally restricted for purposes of settling asset
retirement obligations. Except for the item previously referenced, the
Partnership has determined that there are no other material retirement
obligations associated with tangible long-lived assets.
A reconciliation of the Partnership's liability for well plugging and
abandonment costs for the period ended December 31, 2004 is as follows:
Asset retirement obligation, at beginning of period..... $ -
Liabilities incurred from drilling wells................ 997,000
-------------
Asset retirement obligation, at end of period........... $ 997,000
=============
Revenue Recognition
- -------------------
Revenues from the sale of natural gas and oil are recognized when the gas and
oil are delivered to the purchaser.
56
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Environmental Matters
- ---------------------
The Partnership is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Partnership has
established procedures for the ongoing evaluation of its operations, to identify
potential environmental exposures and to comply with regulatory policies and
procedures.
The Partnership accounts for environmental contingencies in accordance with SFAS
No. 5 "Accounting for Contingencies." Environmental expenditures that relate to
current operations are expensed or capitalized as appropriate. Expenditures that
relate to an existing condition caused by past operations, and do not contribute
to current or future revenue generation, are expensed. Liabilities are recorded
when environmental assessments and/or clean-ups are probable, and the costs can
be reasonably estimated. The Partnership maintains insurance that may cover in
whole or in part certain environmental expenditures. For the period ended
December 31, 2004, the Partnership had no environmental matters requiring
specific disclosure or the recording of a liability.
Major Customers
- ---------------
The Partnership's natural gas is sold under contract to various purchasers. For
the period ended December 31, 2004, sales to UGI Energy Services, Inc., First
Energy Solutions Corporation and American Refining Group accounted for 35%, 18%
and 17% respectively, of total revenues.
NOTE 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.
57
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 4 - PARTICIPATION IN REVENUES AND COSTS
The Managing General Partner and the other partners will generally participate
in revenues and costs in the following manner:
MANAGING OTHER
GENERAL PARTNER PARTNERS (3)
--------------- -------------
Organization and offering costs .............................. 100% 0%
Lease costs................................................... 100% 0%
Revenues...................................................... (1) (1)
Operating costs, administrative costs, direct costs and all
other costs................................................... (2) (2)
Intangible drilling costs..................................... 0% 100%
Tangible equipment costs...................................... 76% 24%
(1) Subject to the Managing General Partner's subordination
obligation, substantially all partnership revenues will be
shared in the same percentage as capital contributions are to
the total partnership capital contributions, except that the
Managing General Partner will receive an additional 7% of the
partnership revenues, which may not exceed 35%.
(2) These costs will be charged to the partners in the same ratio
as the related production revenues are credited.
(3) Other Partners include both investor limited partners and
investor general partners. General Partner units will
automatically convert to limited partner units when all wells
have been drilled and completed. Thereafter, each investor
general partner will have limited liability as a limited
partner under the Delaware Revised Uniform Limited Partnership
Act with respect to his or her interest in the partnership.
NOTE 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:
58
NOTE 5 - TRANSACTIONS WITH ATLAS AND ITS AFFILIATES (CONTINUED)
Drilling contracts to drill and complete wells for the Partnership at cost plus
15%. The cost of the wells includes reimbursement to Atlas of its general and
administrative overhead cost of $14,076 per well and all ordinary and actual
costs of drilling, testing and completing the wells. The Partnership paid
$31,531,000 to Atlas in 2004 under the drilling contracts.
Atlas contributed all the undeveloped leases necessary to cover each of the
Partnership's prospects and received a credit to its capital account in the
Partnership of $1,033,000.
Administrative costs which are included in general and administrative expenses
in the Statement of Operations are payable to Atlas at $75 per well per month.
Administrative costs incurred in 2004 were $6,600.
Monthly well supervision fees which are included in production expenses in the
Statement of Operations are payable to Atlas at $275 per well per month for
operating and maintaining the wells. Well supervision fees incurred in 2004 were
$24,100.
Transportation fees which are included in production expenses in the Statement
of Operations are payable to Atlas generally at $.35 per MCF (one thousand cubic
feet). Transportation costs incurred in 2004 were $34,500.
Anthem Securities, an affiliate of Atlas, received $4,082,500 in 2004 for fees,
commissions and reimbursements as dealer-manager.
Our managing general partner contributed organization and offering costs of
$647,200.
NOTE 6 - COMMITMENTS
As of December 31, 2004, the Partnership has entered into well drilling
contracts with Atlas aggregating $41,775,330 of which $31,531,000 has been paid.
The balance was funded by the Managing General Partner as a component of its
agreed upon capital contribution.
Subject to certain conditions, investor partners may present their interests
beginning in 2009 for purchase by Atlas. The purchase price will be calculated
by Atlas in accordance with the terms of the partnership agreement. Atlas is not
obligated to purchase more than 10% of the units in any calendar year. In the
event that Atlas is unable to obtain the necessary funds, Atlas may suspend its
purchase obligation.
Beginning one year after each of our wells has been placed into production our
managing general partner, as operator, may retain $200 of our revenues per well
per month to cover the estimated future plugging and abandonment costs of the
well.
59
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 7 - SUBORDINATION OF MANAGING GENERAL PARTNER'S REVENUE SHARE
Under the terms of the partnership agreement, Atlas may be required to
subordinate up to 50% of its share of production revenues of the Partnership,
net of related operating costs, administrative costs and well supervision fees
to the receipt by the investor partners of cash distributions from the
Partnership equal to at least 10% of their agreed subscriptions, determined on a
cumulative basis, in each of the first five years of Partnership operations,
commencing with the first distribution of revenues to the investor partners.
NOTE 8 - INDEMNIFICATION
In order to limit the potential liability of any investor general partners,
Atlas has agreed to indemnify each investor that elects to be a general partner
from any liability incurred which exceeds such partner's share of Partnership
assets.
NOTE 9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES
The supplementary information summarized below presents the results of natural
gas and oil activities in accordance with Statements of Financial Accounting
Standards No. 69, "Disclosures About Oil and Gas Producing Activities" ("SFAS
No. 69"). Annually, reserve value information is provided to the investor
partners pursuant to the partnership agreement. The partnership agreement
provides a presentment feature whereby the managing general partner will buy
partnership units, subject to annual limitations, based upon a valuation formula
price in the partnership agreement. Therefore, reserve value information under
SFAS No. 69 is not presented.
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 producing activities at December 31:
2004
------------
Oil and gas properties well drilling contracts........... $ 42,772,300
Mineral interest in properties - proved properties....... 1,033,000
Accumulated depreciation and depletion................... (630,200)
------------
NET CAPITALIZED COSTS................................ $ 43,175,100
============
60
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (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:
2004
-------------
Natural gas and oil sales $ 840,600
Production costs (69,700)
Accumulated depreciation and depletion (630,200)
-------------
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES $ 140,700
=============
(3) COSTS INCURRED
Costs incurred for the period ended December 31, 2004 are as follows:
2004
-------------
Capitalized asset retirement obligation $ 997,000
Acquisition costs 1,033,000
Tangible equipment and drilling costs 41,775,300
-------------
TOTAL INCURRED COSTS $ 43,805,300
=============
(4) RESERVE INFORMATION (UNAUDITED)
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. Refer to regulation S-X rule 4-10 of the Securities
and Exchange Commission contains complete definitions of each of the following
reserve categories. Proved reserves are generally 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 generally are those which are expected to be recovered
through existing wells with existing equipment and operating methods. Proved
undeveloped reserves generally means 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
61
ATLAS AMERICA SERIES #25-2004(B) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (CONTINUED)
acreage are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. 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.
At December 31, 2004, the Managing General Partner contributed well sites from
their lease inventory to drill an estimated 175 gross wells which are expected
to be completed by the end of the second quarter of the year ended December 31,
2005.
NATURAL GAS OIL
(MCF) (BBLS)
------------- -----------
Proved developed and undeveloped reserves:
Acquisition of proved properties 8,568,400 32,700
Production (126,700) (1,200)
------------- -----------
BALANCE, DECEMBER 31, 2004 8,441,700 31,500
============= ===========
NATURAL GAS OIL
(MCF) (BBLS)
------------- -----------
Proved developed reserves:
Beginning of period 0 0
------------- -----------
End of period 3,006,000 13,800
============= ===========
62
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act
of 1934, the registrant has duly caused this Amendment No. 2 to Form 10
Registration Statement to be signed on its behalf by the undersigned, thereunto
duly authorized.
ATLAS AMERICA SERIES 25-2004(B) L.P.
(Registrant)
By: Atlas Resources, Inc.
Managing General Partner
Date: July 13, 2005 By: /s/ Freddie Kotek
---------------------------------------
Freddie Kotek, Chairman of the Board of
Directors, Chief Executive Officer and
President
63
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
1.1 Dealer-Manager Agreement for Atlas America Series 25-2004 Program(2)
1.2 Selected Investment Advisor Agreement(2)
4.1 Certificate of Limited Partnership for Atlas America Series 25-2004(B) L.P. (1)
4.2 Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 25-2004(B)
L.P. (1)
10.1 Drilling and Operating Agreement for Atlas America Series 25-2004(B) L.P. (1)
10.2 Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy
Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. (1)
10.3 Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas Purchase Agreement
dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas
Resources, Inc., and Resource Energy, Inc. (1)
10.4 Master Natural Gas Gathering Agreement dated February 2, 2000 among Atlas Pipeline Partners, L.P. and Atlas
Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and Viking Resources
Corporation (1)
10.5 Omnibus Agreement dated February 2, 2000 among Atlas America, Inc., Resource Energy, Inc., and Viking
Resources Corporation, and Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline Partners, L.P. (1)
10.6 Natural Gas Gathering Agreement dated January 1, 2002 among Atlas Pipeline Partners, L.P., and Atlas Pipeline
Operating Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and Atlas Noble
Corporation, and Resource Energy Inc., and Viking Resources Corporation (1)
10.7 Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc.
and Viking Resources Corp. (1)
10.8 Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp. (1)
10.9 Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc. (1)
10.10 Confirmation of Gas Purchase and Sales Agreement dated November 17, 2004 between Atlas Resources, Inc. et.
al. and First Energy Solutions Corp. for the period from April 1, 2006 through March 31, 2007 production/calendar
periods (1)
10.11 Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy Services, Inc.
d/b/a GASMARK (1)
10.12 Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp. (1)
- ----------
(1) Previously filed on April 29, 2005 in the Form 10 Registration Statement
dated April 29, 2005, File No. 0-51272.
(2) Previously filed on June 17, 2005 in Amendment No. 1 to the Form 10
Registration Statement dated April 29, 2005, File No. 0-51272.