As filed with the Securities and Exchange Commission on April 28, 2006
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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 26-2005 L.P.
(Exact Name of registrant as specified in its charter)
DELAWARE 20-2879859
(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
PAGE PAGE
---- ----
Item 1 Business ....................................1 Our Managing General Partner's
General....................................1 Management Obligations to Us Are
Oil and Natural Gas Properties..........4 Not Exclusive, and if It Does Not
Production..............................5 Devote the Necessary Time to Our
Sale of Natural Gas and Oil Production..5 Management There Could Be Delays
Major Customers.........................8 in Providing Timely Reports and
Competition.............................8 Distributions to Our Participants,
Markets.................................8 and Our Managing General Partner,
Governmental Regulation....................8 Serving as Operator of Our
Regulation of Production................9 Wells, May Not Supervise the
Regulation of Transportation and Sale Wells Closely Enough ................15
of Natural Gas ........................9 Current Conditions May Change and
Environmental Regulation...............11 Reduce Our Proved Reserves, Which
Dismantlement, Restoration, Reclamation Could Reduce Our Revenues ...........16
and Abandonment Costs ................11 Government Regulation of the Oil and
Employees..............................12 Natural Gas Industry is Stringent
Item 1A Risk Factors.................................12 and Could Cause Us to Incur
Risks Relating to Our Business............12 Substantial Unanticipated Costs
Natural Gas and Oil Prices are Volatile for Regulatory Compliance,
and a Substantial Decrease in Prices, Environmental Remediation of Our
Particularly Natural Gas Prices, Well Sites (Which May Not Be Fully
Would Decrease Our Revenues, Our Insured) and Penalties, and Could
Cash Distributions and the Value Delay or Limit Our Drilling
of Our Properties and Could Reduce Operations...........................17
Our Managing General Partner's Our Natural Gas and Oil Activities Are
Ability to Loan Us Funds and Meet Subject to Drilling and Operating
Its Ongoing Obligations to Hazards Which Could Result
Indemnify Our Investor General in Substantial Losses to Us..........18
Partners and Purchase Units Our Total Annual Cash Distributions
Under Our Presentment Feature........12 During Our First Five Years May be
Drilling Wells is Highly Speculative Less than $2,500 Per Unit............18
and We Could Drill Some Wells That Increases in Drilling and Operating
Are Nonproductive or That Costs Could Decrease Our Net Revenues
Are Productive, But Fail to from Our Wells...................... 19
Return the Costs of Drilling and Our Limited Operating History Creates
Operating Them, and the Drilling of Greater Uncertainty Regarding Our
Some of Our Wells Could Be Curtailed, Ability to Operate Profitably........19
Delayed or Cancelled If Unexpected Competition May Reduce Our Revenues
Events Occur ........................14 from the Sale of Our Natural Gas.....20
i
TABLE OF CONTENTS
PAGE PAGE
---- ----
We Sell Our Natural Gas to a Limited Since Our Managing General Partner
Number of Purchasers Without Is Not Contractually Obligated to
Guaranteed Prices, and if the Loan Funds to Us, We Could Have
Prices Paid by the Purchasers to Curtail Operations or Sell
Decrease, Our Revenues Also Will Properties if We Need Additional
Decrease, and if a Purchaser Stops Funds and Our Managing General
Buying Some or All of Our Natural Gas, Partner Does Not Make the Loan.......22
the Sale of Our Natural Gas Could Be Item 2 Financial Information.......................23
Delayed Until We Find Another Selected Financial Data...................23
Purchaser and the Substitute Forward Looking Statements................25
Purchaser We Find May Pay a Lower Results of Operations.....................25
Price, Which Would Reduce Liquidity and Capital Resources...........26
Our Revenues.........................20 Critical Accounting Policies..............26
We Could Incur Delays in Receiving Use of Estimates..........................27
Payment, or Substantial Losses if Reserve Estimates.........................27
Payment is Not Made, for Impairment of Oil and Gas Properties......27
Natural Gas We Previously Delivered Dismantlement, Restoration, Reclamation
to a Purchaser, Which Could Delay and Abandonment Costs ...................28
or Reduce Our Revenues and Commodity Price Risk......................28
Cash Distributions...................21 Item 3 Properties..................................28
If Third-Parties Participating in Drilling Activity.........................28
Drilling Some of Our Wells Fail to Summary of Productive Wells...............29
Pay Their Share of the Well Production................................29
Costs, We Would Have to Pay Those Natural Gas and Oil Reserve Information...30
Costs in Order to Get the Wells Title to Properties.......................32
Drilled, and If We Are Not Acreage...................................33
Reimbursed the Increased Costs Item 4 Security Ownership of Certain Beneficial
Would Reduce Our Cash Flow and Owners and Management ....................33
Possibly Could Reduce the Number of Item 5 Directors and Executive Officers............34
Wells We Can Drill...................21 Managing General Partner..................34
We Expect to Incur Costs in Connection Directors, Executive Officers and
with Exchange Act Compliance and We Significant Employees....................36
May Become Subject to Code of Business Conduct and Ethics.......41
Liability for Any Failure to Comply, Organizational Charts....................41
Which Will Reduce Our Cash Available Item 6 Executive Compensation......................43
for Distribution.....................22 Item 7 Certain Relationships and Related
We Intend to Produce Natural Gas and/or Transactions..............................44
Oil from Our Wells Until They Are Oil and Gas Revenues......................44
Depleted, Regardless of Any Changes Leases....................................44
in Current Conditions, Which Could Administrative Costs......................44
Result in Lower Returns to Our Direct Costs..............................44
Participants as Compared With Other Drilling Contracts........................44
Types of Investments Which Can Adapt
to Future Changes Affecting Their
Portfolios...........................22
ii
TABLE OF CONTENTS
PAGE PAGE
---- ----
Per Well Charges..........................45 Term, Dissolution and Distributions
Gathering Fees............................45 on Liquidation ..........................49
Dealer-Manager Fees.......................45 Transferability...........................50
Organization and Offering Costs...........45 Presentment Feature.......................51
Other Compensation........................45 Voting Rights and Amendments..............53
Item 8 Legal Proceedings...........................45 Books and Records.........................54
Item 9 Market Price of and Dividends on the Restrictions on Roll-Up Transactions......54
Registrant's Common Equity and Related Withdrawal of the Managing General
Stockholder Matters ......................45 Partner..................................56
Item 10 Recent Sales of Unregistered Securities.....46 Item 12 Indemnification of Directors and Officers...56
Item 11 Description of Registrant's Securities to Item 13 Financial Statements and Supplementary Data.57
be Registered ............................47 Item 14 Changes in and Disagreements with
General...................................47 Accountants on Accounting and Financial
Liability of Participants for Further Disclosure................................ 74
Calls and Conversion..................... 47 Item 15 Financial Statements and Exhibits...........74
Distributions and Subordination...........48
Participant Allocations...................49
iii
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. THESE STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT COULD
CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM THE
RESULTS ANTICIPATED IN THOSE STATEMENTS. THESE RISKS INCLUDE RISKS ASSOCIATED
WITH DRILLING AND OPERATING OUR WELLS, MARKETING NATURAL GAS AND OIL PRODUCTION
FROM THE WELLS, AND FLUCTUATIONS IN MARKET PRICES FOR THE NATURAL GAS AND OIL
PRODUCED FROM THE WELLS. FOR A MORE COMPLETE DISCUSSION OF THE RISKS AND
UNCERTAINTIES TO WHICH WE ARE SUBJECT, SEE "RISK FACTORS" IN ITEM 1A. THE TERMS
"WE," "OUR", "US," "ITS" AND THE "COMPANY" USED IN THIS FORM 10 ARE USED AS
REFERENCES TO ATLAS AMERICA SERIES 26-2005 L.P.
GENERAL
We were formed as a Delaware limited partnership on May 26, 2005, with Atlas
Resources, Inc. as our managing general partner. Subsequently, in March 2006,
Atlas Resources, Inc. was merged into Atlas Resources, LLC, a newly-formed
Pennsylvania limited liability company. Our partnership operations began on our
first closing on August 25, 2005. When we had our final closing on September 16,
2005, we had 579 investors who purchased our Units (our "participants"). "Units"
means both our limited partner units and our investor general partner units that
will automatically be converted into limited partner units once all of our wells
are drilled and completed. In accordance with the terms of our offering,
1,338.98 Units were sold at $25,000 per Unit, 55.02 Units were sold at $23,250
per Unit to selling agents and their registered representatives and principals
and clients of a registered investment advisor, and 869.412 Units were sold at
$18,292 per Unit to our managing general partner, and its officers, directors
and affiliates, and 6 Units were sold at 22,125 per Unit to investors who bought
Units through the officers and directors of our managing general partner.
Our participants contributed $34,886,500 in subscription proceeds to us, which
we paid to our managing general partner serving as our operator and general
drilling contractor under our drilling and operating agreement. We used all of
our subscription proceeds to drill and complete wells located primarily in
western Pennsylvania and central Tennessee as described below. Under our
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 all of
the leases on which our wells are situated, pay and/or contribute services
towards our organization and offering costs up to an amount equal to 15% of our
participants' subscription proceeds and pay the majority of our equipment costs
to drill and complete our wells. As of December 31, 2005, the aggregate amount
of these contributions by our managing general partner was $8,979,400.
1
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 production 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 and
Subordination."
Under current conditions, and based in part on the drilling results of
our 99.3125 net initial wells (73% of our total estimated net wells)
which were drilled in 2005, 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 2
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 35.375 net wells (27% of
our total estimated net wells) which we prepaid in 2005 and are
currently in the process of being drilled and completed 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
in 2005, until we have finished all of 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 Item
1A "Risk Factors - Risks Relating to Our Business."
o Obtain federal income tax deductions in 2005 from intangible drilling
costs in an amount guaranteed 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 in us as a limited
partner. For example, if a participant paid $25,000 for a Unit the
investment would produce a 2005 tax deduction of not less than $22,500
per unit, 90%, against:
2
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 2006, our IRS Schedule K-1's to our
participants reported a deduction for intangible drilling costs in
2005 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 2006 for wells we prepaid in 2005, 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.
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 in us, 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 or is a converted 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, 2005, 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:
o quarterly reports on Form 10-QSB;
o annual reports on Form 10-KSB;
3
o current reports on Form 8-K; and
o 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 99.3125 net development wells
and are in the process of completing those wells. In addition, we are drilling
and completing approximately 35.375 additional net development wells, the
participants' costs of which were prepaid in 2005, but which were spudded in the
first quarter of 2006. Because all of our wells have not yet been drilled and
completed, our investor general partner units have not yet 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 capital
contributions to us 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 2005 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 either our
participants or new investors. We pay our managing general partner a monthly
well supervision fee of $285 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:
o well tending;
o routine maintenance and adjustment;
o reading meters and recording production;
o pumping;
o maintaining appropriate books and records; and
o 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.
4
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.
See Item 3 "Properties" for information concerning:
o our natural gas and oil production quantities;
o average sales prices; and
o average production costs.
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 currently will be an amount equal to 10% of the gross sales
price received by us for our natural gas. However, in the following two areas,
we will initially pay a lesser amount:
o in the Armstrong County area our managing general partner anticipates
that the gathering fee, if any, will be $.20 per mcf; and
o in central Tennessee the gathering fee is $.55 per mcf for
transportation of the natural gas plus actual costs for compression.
Also, in the McKean County area, the gathering fees are an amount equal to 10%
of the gross sales price received by us for our natural gas, plus $.35 per mcf
if we use a third-party gathering line. Gross sales price means the price that
is actually received by us, adjusted to take into account proceeds received or
payments made pursuant to hedging arrangements which, for this purpose, include
forward sales transactions.
5
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. See Item 5 "Directors and Executive
Officers - Organizational Charts." 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 as described
above, but which may be increased in the future.
Once all of our wells are drilled, completed and online to sell production, the
majority of our natural gas production initially 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
termination of the guarantee by UGI Corporation on 45 days prior written notice.
Also, our natural gas production from the following areas initially will be sold
as follows:
o in Armstrong County the natural gas initially will be sold to U.S.
Energy Exploration Corporation;
o in McKean County the natural gas initially will be sold to M&M Royalty
Ltd.; and
o in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee the
natural gas initially 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 natural gas
sold through interconnects established after the date of the agreement with
Amerada Hess Corporation, which includes the majority of natural gas produced
from our wells in Fayette County and natural gas produced from our well(s) that
are operated by a third-party or are 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 and McKean Counties, Pennsylvania
and Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee. Our
managing general partner cannot predict whether this will change in the future.
6
The delivery and pricing arrangements with our natural gas purchasers, including
UGI Energy Services, Amerada Hess Corporation, Colonial Energy, U.S. Energy
Exploration Corporation, M&M Royalty Ltd. and Duke Energy, are tied to the
settlement 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 $.51 and $1.07
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 forward sales transactions (which are not considered hedging for
accounting purposes) through its natural gas purchasers as described below, and
hedges through contracts such as 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 our 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, Amerada Hess
Corporation and Colonial Energy, also use NYMEX based financial instruments to
hedge their pricing exposure, and they make price hedging opportunities
available to our managing general partner for us and our managing general
partner's other partnerships. As of April 2, 2006, the majority of our managing
general partner's natural gas was subject to forward sales transactions through
March 31, 2007. The forward sales transactions are similar to NYMEX based
futures contracts, swaps and options, but also require firm physical delivery of
the natural gas. Because of this, 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 forward sales transactions,
we are not required to provide any fixed and determinable quantities of natural
gas under any agreement. Also, the price paid by UGI Energy Services, Amerada
Hess Corporation, Colonial Energy and any other third-party marketers for
certain volumes of natural gas sold under these agreements may be significantly
different from the underlying monthly spot market value.
7
The portion of natural gas that is subject to forward sales transactions and the
form of the transaction (e.g. fixed pricing, floor and/or costless collar
pricing) changes from time to time. In addition, on October 27, 2005, our
managing general partner and its affiliates implemented financial hedges through
its banking counter-party, Wachovia Bank, and as of April 2, 2006, our managing
general partner and its affiliates have hedged approximately 63% of their
production using fixed-for-floating financial swaps for the period April 1, 2007
though December 31, 2008, and approximately 21% for the period July 1, 2006
through December 31, 2009.
It is difficult to project what portion of these forward sales transactions
through the natural gas purchasers and hedges will be allocated to us by our
managing general partner because of uncertainty about the quantity, timing, and
delivery locations of natural gas that may be produced by us. Although hedging
and the forward sales transactions provide us some protection against falling
prices, these activities also could reduce the potential benefits of price
increases.
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, 2005, sales to U.S. Energy
Exploration Corporation, Dominion Field Services, Inc. and Amerada Hess
Corporation, accounted for 66%, 23%, 11%, respectively of total revenues. No
other customer accounted for more than 10% of total revenues for the period
ended December 31, 2005.
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.
MARKETS. The availability of a ready market for natural gas and oil, and the
price obtained, depend on numerous factors beyond our control as described below
in Item 1A "Risk Factors - Risks Relating to Our Business." During fiscal 2005,
2004, and 2003 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 those periods.
8
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 that 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.
9
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;
10
o discharge permits for drilling operations;
o various reporting requirements; and
o well plugging standards and procedures.
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 (currently 38.31% to our managing general partner and 61.69%
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, which we estimate will charged be 74.18% to
our managing general partner and 25.82% to our participants.
11
As a consequence of the allocation provisions of the partnership agreement
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 our participants' potential shortfall, beginning one year after each of
our wells has been placed into production our managing general partner, serving
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. Instead, we rely on our managing general
partner for management services, and our managing general partner relies on its
parent company, Atlas America, Inc., for certain management and administrative
services. See Item 5 "Directors and Executive Officers."
ITEM 1A. 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 those 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. Also, our participants' return level will decrease during our term,
even if there are rising natural gas prices, because of reduced production
volumes from our wells.
12
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 $11.06 per mcf in the quarter ended December 31, 2005 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;
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 and/or war or terrorist acts 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 other countries (which our managing
general partner believes becomes economic when natural gas prices are
at or above $3.50 per mcf), and 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.
13
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
our investor general partners for liabilities in excess of their pro rata share
of our assets and insurance proceeds and purchasing units presented by our
participants, although this presentment right may be suspended by our 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 consideration
for this purpose on reasonable terms. Also, see Item 5 "Directors and Executive
Officers - Managing General Partner," regarding the reorganization of our
managing general partner and its affiliates.
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
and forward sales transactions provide us some protection against falling
natural gas prices, hedging and forward sales transactions 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
those arrangements.
DRILLING WELLS IS HIGHLY SPECULATIVE AND WE COULD DRILL SOME WELLS THAT ARE
NONPRODUCTIVE OR THAT 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 that are nonproductive (i.e. "dry holes"), or wells that are
profitable on an operating basis, but 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 whether or not natural gas or oil is present
or can be produced economically.
14
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 by our managing general partner,
serving as our general drilling contractor, at cost plus a nonaccountable fixed
payment reimbursement to our managing general partner for our participants'
share of our managing general partner's general and administrative overhead of
$15,000 per well, plus 15% of the cost and the nonaccountable fee fixed payment
reimbursement.
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 natural gas and oil production revenues, thereby reducing or delaying
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 administration as a partnership and our natural gas and oil operations are
managed properly.
15
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 they are produced from our wells, 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, 2005 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 the 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 the following:
o the actual production history of our wells;
o results of future exploration and development in the area;
16
o prevailing natural gas and oil prices;
o governmental regulation; and
o 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 COULD DELAY OR LIMIT OUR DRILLING OPERATIONS. 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 Item 1 "Business - 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 rigs and other heavy equipment from
using certain roads during winter. This is important to us, because in 2005 we
prepaid the costs of certain wells, including the currently deductible
intangible drilling costs of the wells, and the drilling of each of those
prepaid wells was to begin on or before March 30, 2006 under our drilling and
operating agreement. Although the drilling of all of our prepaid wells began on
or before March 30, 2006, government regulations such as the "frost laws" could
delay the completion of our prepaid wells. Also, governmental regulations could
change in ways that substantially increase our costs, thereby reducing our
return on invested capital, revenues and net income.
Our operations may cause us to 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 begins;
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
17
o impose substantial liabilities for pollution resulting from our
operations.
Failure to comply with these laws and regulations may result in the following:
o assessment of administrative, civil, and criminal penalties;
o incurrence of investigatory or remedial obligations; or
o 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 Item 1 "Business - 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, 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.
OUR TOTAL ANNUAL CASH DISTRIBUTIONS DURING OUR FIRST FIVE YEARS MAY BE LESS THAN
$2,500 PER UNIT. 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 our 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," above.
18
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. Although
shortages of drilling rigs, equipment, supplies or personnel have not delayed
the drilling of our wells, such shortages could delay completing some of our
wells or connecting them to gathering lines, which would delay our receipt of
production revenues from the wells.
OUR LIMITED OPERATING HISTORY CREATES GREATER UNCERTAINTY REGARDING OUR ABILITY
TO OPERATE PROFITABLY. Our limited history of operating our wells may not
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:
o borrow funds from our managing general partner, which is not
contractually obligated to make any loans to us;
o shut-in or curtail production from some of our wells; or
o 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 our 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;
19
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.
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 and we may receive lower prices for our natural gas and 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 initially on a limited number of natural gas purchasers
to purchase the majority of our natural gas production as described in Item 1
"Business - General - Sale of Natural Gas and Oil Production" and "- General -
Major Customers," and we will not be guaranteed a specific natural gas price,
other than through hedging and forward sales transactions. For example, for the
period ended December 31, 2005, U.S. Energy Exploration Corporation, Dominion
Field Services, Inc., and Amerada Hess Corporation accounted for 66%, 23%, and
11%, respectively, of total revenues. No other customer accounted for 10% or
more of total revenues for the period ended December 31, 2005. Thus, if our
current purchasers, including UGI Energy Services, Inc., Amerada Hess
Corporation, and U.S. Energy Exploration 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., Amerada Hess
Corporation and U.S. Energy Exploration 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 Item 1 "Business - General - Markets."
20
Also, our managing general partner anticipates that it will use the gathering
system owned by Atlas Pipeline Partners for the majority of our natural gas as
described in Item 1 "Business - General - Sale of Natural Gas and Oil
Production." Atlas Pipeline Partners GP, LLC, a wholly-owned subsidiary of Atlas
Pipeline Holdings, L.P., an affiliate of Atlas America, Inc., which is sometimes
referred to in this Form 10 as "Atlas America" and is the indirect parent
company of our managing general partner, controls and manages the gathering
system for Atlas Pipeline Partners. (See Item 5 "Directors and Executive
Officers - Organizational Charts.") Atlas Pipeline Holdings, L.P., as a public
company, may be more susceptible to a change of control from Atlas America's
affiliates to independent third-parties. Also, if Atlas Pipeline Partners GP,
LLC were removed as general partner of Atlas Pipeline Partners without cause and
without its consent, this could increase the amount of gathering fees required
to be paid by us for natural gas transported through Atlas Pipeline Partners'
gathering system. This could happen, because Atlas Pipeline Partners GP, LLC
would no longer receive revenues from Atlas Pipeline Partners, but Atlas America
and its affiliates would be obligated to pay the difference between the amount
in the master natural gas gathering agreement and the amount paid by us.
Although there is an exception with respect to new wells drilled after the
removal of the general partner, we do not anticipate that we would still be
drilling new wells at that time. Thus, our managing general partner and its
affiliates may have an incentive to increase the gathering fees we pay, which
would reduce our cash distributions.
WE COULD INCUR DELAYS IN RECEIVING PAYMENT, OR SUBSTANTIAL LOSSES IF PAYMENT IS
NOT MADE, FOR NATURAL GAS WE PREVIOUSLY DELIVERED TO A 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 forward sales transactions as described in Item 1
"Business - General - Sale of Natural Gas and Oil Production," since a portion
of our managing general partner's natural gas is subject to forward sales
transactions implemented through the natural gas purchasers.
IF THIRD-PARTIES 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.
21
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 we 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.
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.
22
ITEM 2. FINANCIAL INFORMATION.
SELECTED FINANCIAL DATA. The following table sets forth selected financial data
for the period ended December 31, 2005, that we derived from our financial
statements, which were audited by Grant Thornton LLP, independent registered
public accountants, and are included in this Form 10.
FOR THE PERIOD MAY 26, 2005
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2005
---------------------------------------
INCOME STATEMENT DATA:
Revenues:
Gas and oil production .................................................. $34,700
---------
Total revenues....................................................... $34,700
=========
Costs and expenses:
Gas and oil production.................................................... $2,100
Transmission.............................................................. 400
General and administration................................................ 13,600
Depletion................................................................. 7,600
---------
Total costs and expenses....................................................... $23,700
=========
Net income..................................................................... 11,000
---------
Basic and diluted net earnings per limited partnership unit.................... $3
=========
23
FOR THE PERIOD MAY 26, 2005
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2005
----------------------------
OPERATING DATA:
Net annual production volumes:
Natural gas (mmcf) (1) .................................................. 3,073
Oil (mbbls).............................................................. -
-----------
Total (mmcfs).................................................................. 3,073
===========
Average sales price:
Natural gas (per mcf).................................................... $11.31
Oil (per bbl) ........................................................... $-
OTHER FINANCIAL INFORMATION:
Net cash used in operating activities.......................................... $17,219,700
Capital expenditures .......................................................... $17,666,800
EBITDA (2).................................................................... $18,600
FOR THE PERIOD MAY 26, 2005
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2005
---------------------------------
BALANCE SHEET DATA:
Total assets................................................................... $39,922,900
===========
Total liabilities ............................................................ $581,100
===========
Partners' capital.............................................................. $39,341,800
===========
(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 our participants to understand our operating
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 from, or as a
substitute for, our net income as an indicator of operating 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.
24
FOR THE PERIOD MAY 26, 2005
(DATE OF FORMATION)
THROUGH DECEMBER 31, 2005
--------------------------------------
Income from continuing operations............................................... $11,000
Plus depletion ................................................................. 7,600
-------
EBITDA.......................................................................... $18,600
=======
FORWARD-LOOKING STATEMENTS. When used in this Form 10, the words "believes,"
"anticipates," "expects" and similar expressions are intended to identify
forward-looking statements. These statements are subject to certain risks and
uncertainties more particularly described in Item 1A "Risk Factors" of this Form
10. These risks and uncertainties could cause our actual results to differ
materially from those that we anticipate. Readers are cautioned not to place
undue reliance on these forward-looking statements, which speak only as of the
date of this Form 10. We undertake no obligation to publicly release the results
of any revisions to forward-looking statements that we may make to reflect
events or circumstances after the date of this Form 10 or to reflect the
occurrence of unanticipated events.
This "Financial Information" section should be read in conjunction with Item 13
"Financial Statements and Supplementary Data - Notes to Financial Statements."
RESULTS OF OPERATIONS. The following table sets forth information for the period
May 26,2005 (date of formation) through December 31, 2005 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:
PERIOD ENDED
DECEMBER 31, 2005
--------------------------------------
Revenues (in thousands):
Gas(1) ............................................................ $34,747
Oil................................................................ $-
Production volumes:
Gas (thousands of cubic feet (mcf)/day)............................ 29
Oil (barrels (bbls)/day)........................................... -
Average sales price:
Gas (per mcf)...................................................... $11.31
Oil (per bbl)...................................................... $-
Production costs:
As a percent of sales.............................................. 7%
Per equivalent mcf................................................. $.81
Depletion per mcfe...................................................... $2.48
- ---------
(1) Excludes sales of residual gas and sales to landowners.
25
LIQUIDITY AND CAPITAL RESOURCES. Cash used in investing activities was
$17,666,800 for the period ended December 31, 2005, which was paid to our
managing general partner, serving as general drilling contractor, pursuant to
our drilling and operating agreement. Cash provided by financing activities was
$34,886,600 which came from capital contributions for the period ended December
31, 2005.
Our managing general partner believes that we have adequate capital to develop
approximately 144 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, and no
other wells will be drilled after this initial group. Although we estimate that
144 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 that there
will be a shortfall in our revenues that we use to pay for our ongoing expenses,
if one 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.
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 intend to 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.
CRITICAL ACCOUNTING POLICIES. The discussion and analysis of our financial
condition and results of operations are based on 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 costs 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 our managing general partner's historical
experience and on various other assumptions that we believe are 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.
26
We have identified the following policies as critical to our business operations
and understanding the results of our operations. For a detailed discussion on
the application of these and other accounting policies, see Note 2 in Item 13
"Financial Statements and Supplementary Data - 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
our future net revenues from them will be based on reserve analyses that rely on
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 the estimates contained in the reserve reports. In addition, our
proved reserves may be subject to downward or upward revision based on
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 the 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 impairments may be required in the
future.
27
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 on abandonment. We account
for abandonment costs using SFAS 143, "Accounting for Asset Retirement
Obligations," as discussed in Note 3 to our consolidated financial statements in
Item 13 "Financial Statements and Supplementary Data - Notes to Financial
Statements." As of December 31, 2005, 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
natural 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 natural 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, 2006, we
estimate in excess of 66% 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, 2005 we had drilled 102 gross wells, which
is 99.3125 net wells, and seven of these wells were online for the sale of
production 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 wells we drilled during 2005, our participants' share of our
estimated drilling and equipment costs of approximately 35.375 net wells were
prepaid by us in 2005. The drilling of each of the wells we prepaid in 2005
began on or before March 31, 2006, and those prepaid wells are not included in
the following table.
28
DEVELOPMENT WELLS
-------------------------------------------------------------------------
PRODUCTIVE (1) DRY (2)
------------------------------------ ---------------------------------
GROSS (3) NET (4) GROSS (3) NET (4)
---------------- -------------- ------------- ---------------
PERIOD ENDING DECEMBER 31, 2005 7 6.25 1 1
- -----------
(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 owned a working interest at
December 31, 2005. All of our wells are classified as natural gas wells.
LOCATION GROSS NET
----- ---
Pennsylvania....................................................... 7 6.25
Tennessee.......................................................... - -
----------- ------------
Total ....................................................... 7 6.25
=========== ============
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.
PRODUCTION AVERAGE SALES PRICE AVERAGE PRODUCTION COST
--------------------------- ------------------------ (LIFTING COST)
PERIOD FROM FIRST PRODUCTION OIL (BBLS) GAS (MCF) PER BBL PER MCF (1) PER MCFE (1)(2)
---------- --------- -------- ----------- ------------------------
TO DECEMBER 31, 2005..............
- 3,100 $- $11.31 $.81
29
- ----------
(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.
AT DECEMBER 31, 2005
Natural gas (per mcf)............................. $10.28
Oil (per bbl)..................................... $--
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 revising 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.
30
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
Item 13 "Financial Statements and Supplementary Data - Notes to Financial
Statements."
AT DECEMBER 31, 2005
Natural gas reserves - Proved Reserves (Mcf)(1)(5):
Proved developed reserves (2)...................................... 8,285,949
Proved undeveloped reserves (3).................................... -
-----------
Total proved reserves of natural gas............................... 8,285,949
===========
Oil reserves - Proved Reserves (Bbl)(1)(5)
Proved developed reserves (2)...................................... -
Proved undeveloped reserves (3).................................... -
Total proved reserves of oil....................................... -
-----------
Total proved reserves (Mcfe)........................................... 8,285,949
===========
PV-10 estimate of cash flows of proved reserves (4)(5):
Proved developed reserves.......................................... $34,334,917
Proved undeveloped reserves........................................ -
-----------
Total PV-10 estimate $34,334,917
===========
- ----------
(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.
31
(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 Item 13 "Financial Statements and Supplementary Data - Notes to
Financial Statements."
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 begin
drilling operations, however, we conduct an extensive title examination and
perform curative work on any 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
32
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, 2005.
LOCATION DEVELOPED ACREAGE UNDEVELOPED ACREAGE (3)
- -------- ----------------- -----------------------
GROSS (1) NET (2) GROSS (1) NET (2)
--------- ------- --------- -------
Pennsylvania ........................ 2,994 2857.50 - -
Tennessee ........................... 920 847.50 - -
----- --------
Total ......................... 3,914 3,705.00 - -
- ----------
(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 in the form of forward sales transactions with our natural gas
purchasers.
ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
As of December 31, 2005, we had issued 1,400 Units to 579 participants. The
following table, as of December 31, 2005, 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.
33
UNITS
--------------------------------------------
AMOUNT AND NATURE OF
BENEFICIAL OWNER BENEFICIAL OWNERSHIP PERCENT OF CLASS
- ---------------- ---------------------- -----------------
DIRECTORS AND EXECUTIVE OFFICERS
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 UNITS
None............................................................ 0 0%
We are not aware of any arrangements which may, at a subsequent date, result in
a change in our control.
ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS
MANAGING GENERAL PARTNER. We will have no officers, directors or employees.
Instead, Atlas Resources, LLC, a Pennsylvania limited liability company, which
was originally formed as a corporation in 1979 and then changed to a limited
liability company on March 28, 2006, 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 $45.7
million, $21.6 million, and $13.1 million for our managing general partner's
fiscal years ended September 30, 2005, 2004, and 2003, respectively.
34
Atlas America, Inc. recently announced that it intends to transfer into a
wholly-owned limited liability company or limited partnership subsidiary of
Atlas America, Inc. substantially all of its natural gas and oil exploration and
production assets, and make a registered initial public offering of a minority
interest, estimated to be 20%, in its newly-formed subsidiary. This Form 10 does
not constitute an offer to sell or a solicitation of an offer to buy any such
securities. Rather than transferring those energy assets directly to its
newly-formed subsidiary, which Atlas America anticipates will be a Pennsylvania
limited liability company named "Atlas Energy, LLC," Atlas America intends to
make Atlas Energy, LLC the indirect owner of the energy assets by changing the
Atlas America subsidiaries that currently own those assets, including our
managing general partner, into limited liability company subsidiaries of Atlas
Energy, LLC, and liquidating certain inactive subsidiaries of Atlas America.
Atlas America anticipates that all of these transactions will be completed
sometime during 2006 and before or upon the closing of the intended public
offering of interests in Atlas Energy, LLC discussed above. The anticipated
effect of Atlas America's intended transactions in connection with Atlas Energy,
LLC can be seen by comparing the "- Current Organizational Diagram" with the "-
Pro Forma Organizational Diagram (Subject to Change)" in "- Organizational
Charts," below.
Our managing general partner and its affiliates under Atlas America employ a
total of more than 200 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 September 1998, Atlas Energy Group, Inc., the former parent company of our
managing general partner, merged into Atlas America, Inc., a Delaware holding
company, which was 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. 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.
After the public offering, Resource America continued to own approximately
80.2% of Atlas America's common stock until it distributed all of its remaining
10.7 million shares of common stock in Atlas America to its common stockholders
on June 30, 2005 in the form of a spin-off by means of a tax free dividend of
approximately 0.6 shares of Atlas America to Resource America common
stockholders for each share of Resource America common stock owned.
35
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 50 Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas 46 Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons 47 Executive Vice President - Operations and a Director
Jack L. Hollander 50 Senior Vice President - Direct Participation Programs
Nancy J. McGurk 50 Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines 56 Senior Vice President, Secretary and a Director
Michael G. Hartzell 50 Vice President - Land Administration
Donald R. Laughlin 58 Vice President - Drilling and Production
Marci F. Bleichmar 35 Vice President of Marketing
Karen A. Black 45 Vice President - Partnership Administration
Sherwood S. Lutz 55 Senior Geologist/Manager of Geology
Michael W. Brecko 48 Director of Energy Sales
Justin T. Atkinson 33 Director of Due Diligence
Winifred C. Loncar 65 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.
36
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
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.
37
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.
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.
38
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.
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.
39
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.
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.
40
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. Atlas America owns 100% of the common stock of AIC, Inc.,
which owns 100% of the common stock of our managing general partner. The
directors of AIC, Inc. are Jonathan Z. Cohen, Michael L. Staines, and Jeffrey C.
Simmons. The biographies of Messrs. Staines and Simmons are set forth above.
CURRENT ORGANIZATIONAL DIAGRAM
[GRAPHIC OMITTED]
------------------------------------------
Atlas America, Inc. (Delaware)
(driller and operator in Ohio) (1) (4)
------------------------------------------
|
|
|
- --------------------- -------------------- ------ -------------------- --------------- ------------- ------------- ------------
Atlas Pipeline Atlas Pipeline AIC, Atlas America, Inc. Viking Resource Atlas Noble AED
Holdings, L.P. (3) Holdings GP, LLC, Inc. (Pennsylvania) Resources Energy, Inc. Corporation Investments,
- --------------------- non-economic general (operating company) Corporation (2) (2) (2) Inc.
partner interest in ------ ------------------- --------------- ------------- ------------- ------------
- ------------------ Atlas Pipeline
Atlas Pipeline Holdings, L.P.
Partners GP, LLC, --------------------
general partner
interest in ------------------------- ------------------------- ------------- ------------------
Atlas Pipeline Atlas Resources, LLC, Atlas Energy Pennsylvania Anthem
Partners, L.P. managing general partner Corporation, managing Industrial Securities, Inc.,
- ------------------ of Atlas America general partner of Energy, Inc registered
Series 26-2005 L.P., exploratory drilling broker/dealer
- ------------------ driller and operator partnerships and driller and
Atlas Pipeline in Pennsylvania and operator dealer-manager
Partners, L.P. ------------------------- -------------------------- ------------ ------------------
- ------------------
---------------------
ARD Investments, Inc.
- ------------------ ---------------------
Atlas Pipeline
Operating
Partnership, L.P.
- ------------------
- --------------
(1) See "- Managing General Partner," above, for a discussion of Atlas
America's stock offering in 2004.
41
(2) Viking Resources, Resource Energy, and Atlas Noble Corporation are also
engaged in the oil and gas business. Atlas America manages their assets
and employees including sharing common employees. Also, many of the
officers and directors of our managing general partner serve as
officers and directors of those entities.
(3) On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned
subsidiary of Atlas America, filed a registration statement with the
SEC for an initial public offering of 3,600,000 common units,
representing an approximate 17.1% limited partner interest in it. On
the successful completion of the offering, Atlas Pipeline Holdings,
L.P. will own Atlas Pipeline Partners GP, LLC, which owns a 2.0%
general partner interest, all the incentive distribution rights and an
approximate 12.8% limited partner interest in Atlas Pipeline Partners,
L.P. Atlas America will continue to own Atlas Pipeline Holdings GP,
LLC, which gives Atlas America indirect general partner control over
Atlas Pipeline Partners.
(4) See "- Managing General Partner," above, and "- Pro Forma
Organizational Diagram (Subject to Change)," below, regarding Atlas
America's recent announcement that it intends to form a new subsidiary
to own its natural gas and oil exploration and production assets, and
conduct a public offering of a minority interest, estimated to be 20%,
in the new subsidiary. This Form 10 does not constitute an offer to
sell or a solicitation of an offer to buy any such securities.
PRO FORMA ORGANIZATIONAL DIAGRAM (SUBJECT TO CHANGE)
The following pro forma organizational diagram is subject to change, because it
reflects certain transactions that Atlas America anticipates will happen in the
near future, but which have not yet happened as of the date of this Form 10. The
anticipated transactions set forth in the following diagram include, for
example, Atlas America's formation of new wholly-owned subsidiaries Atlas
Energy, LLC and Atlas Energy Manager LLC, changing many of its corporate
subsidiaries to limited liability subsidiaries of Atlas Energy LLC, and
liquidating certain inactive corporate subsidiaries. The changes in the
following organizational diagram from the "- Current Organizational Diagram" set
forth above, relate to Atlas America's recent announcement that it intends to
transfer to a newly-formed subsidiary of Atlas America substantially all of its
natural gas and oil exploration and production assets. Atlas America anticipates
that all of these transactions will be completed before or upon the closing of
Atlas Energy, LLC's public offering as described in "- Managing General
Partner," above. This prospectus does not constitute an offer to sell or a
solicitation of an offer to buy any such securities.
42
[GRAPHIC OMITTED]
------------------------------
Atlas America, Inc.
(A Delaware corporation) (1)
------------------------------
|
|
- ------------------ -------------------- ----------------------- -------------------------
Atlas Pipeline Atlas Pipeline Atlas Energy, LLC (2) Atlas Energy Manager,
Holdings, L.P. (3) Holdings GP, LLC, (Pennsylvania) LLC, manager of Atlas
- ------------------ non-economic general ----------------------- Energy, LLC (2)
partner interest in -------------------------
Atlas Pipeline
- ------------------ Holdings, L.P.
Atlas Pipeline ---------------------
Partners GP, LLC,
general partner ------------------ ----------------- ---------------- ----------------- -----------------
interest in Atlas AIC, LLC Atlas Noble, Resource Energy, Viking Resources, Atlas America,
Pipeline Partners, LLC (2) LLC (2) LLC (2) LLC (2)
L.P. ------------------ ----------------- ---------------- ----------------- -----------------
- ------------------
--------------
- ------------------ Atlas Energy,
Atlas Pipeline LLC (2) ---------------
Partners, L.P. (Ohio) REI-NY, LLC (2)
- ------------------ -------------- ---------------
- ------------------ ----------------
Atlas Pipeline Atlas Resources, ------------------
Operating LLC (2) Resource Well
Partnership, L.P. ---------------- Services, LLC (2)
- ------------------ ------------------
------------------
Anthem Securities,
Inc.
------------------
- -----------
(1) See "- Managing General Partner," above, for a discussion of Atlas
America's stock offering in 2004.
(2) All of these companies would be engaged in the oil and gas exploration
and production business. Atlas America would continue to manage their
assets and employees including sharing common employees. Also, many of
the officers and directors of our managing general partner would serve
as officers and directors of those entities.
(3) On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned
subsidiary of Atlas America, filed a registration statement with the
SEC for an initial public offering of 3,600,000 common units,
representing an approximate 17.1% limited partner interest in it. On
the successful completion of the offering, Atlas Pipeline Holdings,
L.P. will own Atlas Pipeline Partners GP, LLC, which owns a 2.0%
general partner interest, all the incentive distribution rights and an
approximate 12.8% limited partner interest in Atlas Pipeline Partners,
L.P. Atlas America will continue to own Atlas Pipeline Holdings GP,
LLC, which gives Atlas America indirect general partner control over
Atlas Pipeline Partners.
ITEM 6. EXECUTIVE COMPENSATION.
We have no employees and rely on the employees of our managing general partner
and its affiliates to manage us and our business. Our managing general partner
depends on its 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 $45.7 million, $21.6 million, and $13.1 million for
its fiscal years ended September 30, 2005, 2004, and 2003, respectively. 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.
43
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
OIL AND GAS REVENUES. Our managing general partner currently is allocated 38.31%
of our natural gas and oil revenues in return for paying and contributing
services towards our organization and offering costs estimated to be 13% of our
subscriptions, paying an estimated 74.18% 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 estimated to be $15,903,600 .
During the period ended December 31, 2005, we did not pay any cash distributions
to our managing general partner or our participants.
LEASES. During the period ended December 31, 2005, our managing general partner
contributed undeveloped prospects (leases) to us to drill 99.3125 net wells, and
received a credit to its capital account in us in the amount of $839,900. Our
managing general partner anticipates entering into further lease transactions
with us.
ADMINISTRATIVE COSTS. Our managing general partner and its affiliates receive an
unaccountable, fixed payment reimbursement from us 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 $400 in these fees for the period ended December 31, 2005.
DIRECT COSTS. Our managing general partner and its affiliates will be reimbursed
by us for all direct costs expended by them on our behalf, whether our managing
general partner is acting as our managing general partner or as the operator of
our wells. For the period ended December 31, 2005, we reimbursed our managing
general partner $13,900 for these direct costs.
DRILLING CONTRACTS. We entered into a drilling and operating agreement with our
managing general partner, acting as our general drilling contractor, after our
initial and final closing dates to drill and complete 134.6875 net wells. The
total amount received by our managing general partner from our subscription
proceeds was $34,886,500. This amount was paid by our participants for their
share of the costs of drilling and completing the wells, including the wells
that were prepaid in 2005, but the drilling of which was to begin on or before
March 30, 2006. We have not entered into any other drilling transactions to the
date of this filing, and none are anticipated by us for future periods.
44
PER WELL CHARGES. Our managing general partner, serving as operator of our
wells, 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 our wells during producing operations in the
amount of $285 per well per month subject to annual adjustments for inflation.
During the period ended December 31, 2005, our managing general partner received
$1,400 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,
2005, the amount paid was $400. Of this amount, 100% was paid by our managing
general partner to Atlas Pipeline Partners.
DEALER-MANAGER FEES. As part of the offering of our Units, our managing general
partner's affiliate, Anthem Securities, Inc., serving as dealer-manager of the
offering, received a 2.5% dealer-manager fee, a 7% sales commission, a 1.5%
nonaccountable marketing expense fee, and a .5% accountable due diligence fee in
the aggregate amount of $3,906,580. The dealer-manager will receive no further
compensation from us. Of this amount, $3,139,782 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, 2005, our
managing general partner paid and contributed services for our organization and
offering costs in the amount of $4,535,200, including the compensation paid to
the dealer-manager, which did not exceed 13% of our subscription proceeds.
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, 2005, no advances were made to
us by our managing general partner and we did not enter into any contracts with
our managing general partner for equipment, supplies and other services to us
other than our partnership agreement and our drilling and operating agreement.
ITEM 8. LEGAL PROCEEDINGS.
None
45
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, 2005, there were no outstanding options or warrants to
purchase, or securities convertible into, our Units. In addition, as of December
31, 2005, 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, 2005, there were 579 holders of records of our 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 Item 11
"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. 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 our 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, 2005, we made no cash distributions.
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES.
We sold 1,400 Units to 579 investors in a private placement offering of our
Units beginning July 15, 2005 and ending August 31, 2005. 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 our Units were $34,886,500.
46
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. Our Units were offered and sold to a limited number of persons who had
the sophistication to understand the merits and risks of the investment, who had
the financial ability to bear those risks, and who were "accredited investors,"
as that term is defined in Regulation D (17 CFR 230.501(a)). All of our
participants 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 our Units (i.e., our
participants) are governed by our partnership agreement. "Units" means 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 discussion is a
summary of some of the provisions of our partnership agreement that are 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 Resources, LLC, 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.
47
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, because we have not yet drilled and completed all
of our wells.
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 our obligations and liabilities that
arise 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 liabilities and obligations that we 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. 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. 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 our total
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 40% of our revenues regardless of the amount of its
capital contributions to us. As of December 31, 2005, our managing general
partner received 38.31% of our production revenues and our participants received
61.69% of our production revenues. Subject to the foregoing, these sharing
percentages will be adjusted based on the final amount of our managing general
partner's capital contributions to us after all of our wells have been drilled
and completed. See our partnership agreement for special allocations between our
managing general partner and our participants of equipment proceeds, lease
proceeds and interest income.
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 20% 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 all of his capital during our term, because the
subordination is not a guarantee.
48
Our 60-month subordination period will begin with our first cash distribution of
revenues from operations in 2006. Subordination distributions will be determined
by debiting or crediting our current period 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.
PARTICIPANT ALLOCATIONS. Our 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 a Unit. 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 to acquire their Units.
Thus, our intangible drilling costs and our participants' share of our equipment
costs to drill and complete 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 by an event which causes the dissolution of a
limited partnership under the Delaware Revised Uniform Limited Partnership Act.
However, if an event which causes our dissolution under state law 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.
49
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 distributions to our
participants.
TRANSFERABILITY. Our Units may not be sold, assigned or otherwise transferred
unless certain conditions set forth in our 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 making the
transfer owns less than a whole Unit, in which case the entire
fractional interest in the Unit 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 our managing
general partner; and
o the terms of the transfer must not contravene those of our partnership
agreement.
50
A transfer of a participant's Unit will not relieve the participant of
responsibility for any obligations related to his Unit under the partnership
agreement. Also, the transfer of a Unit 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 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
intangible drilling costs 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 his Units.
Under our partnership agreement, an assignee (transferee) of a Unit may become a
substituted partner only on meeting certain further conditions. The conditions
to become a substituted partner are as follows:
o the assignor (transferor) 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 substituted 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 2010 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.
51
Our managing general partner has no obligation to establish a reserve to satisfy
the presentment obligation, and it does not intend to do so. Our managing
general partner 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 participant's entire interest in us, nor more
than 5% of our total Units in any calendar year. If fewer than all of the 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 5% of our total Units in any calendar year.
Our managing general partner's obligation to purchase the Units presented by our
participants 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 our 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 was made.
The amount of the presentment price attributable to our natural gas and oil
reserves will be determined based on our last reserve report. Beginning in 2007
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 year beginning in 2007.
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 our proved reserves determined as described above;
52
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 our
partnership agreement.
VOTING RIGHTS AND AMENDMENTS. Other than as set forth below, a participant
generally will not be entitled to vote on any of our partnership matters at any
meeting. However, at any time participants whose Units equal 10% or more of our
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 the participant owns a fractional Unit, that fraction of one vote equal to
the fractional interest in the Unit. Participants whose Units equal a majority
of our total Units may vote to:
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;
53
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 for the offering of our Units or our
partnership agreement without penalty on 60 days notice; and
o amend our 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 our 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 our total Units. Our
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.
RESTRICTIONS ON ROLL-UP TRANSACTIONS. In connection with any proposed
transaction which is considered 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:
54
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 each 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 our 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
our partnership agreement to the greatest extent possible;
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;
55
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 our 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 our 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 our 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 our
total Units. If our participants, however, choose to terminate our 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 our 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 our behalf or performing services for us; and
o their course of conduct did not constitute negligence or misconduct.
In addition, our partnership agreement provides for our indemnification of our
managing general partner, the operator, and their affiliates 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 our partnership agreement purports to include indemnification for
liabilities arising under the Securities Act of 1933, as amended, in the SEC's
opinion this indemnification is contrary to public policy and therefore
unenforceable.
56
Payments arising from the indemnification or agreement to hold harmless
described above are recoverable only out of our tangible net assets, revenues,
and insurance proceeds. Still, the 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.
Under our partnership agreement, we are not allowed to 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 as described above. 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 our partnership agreement are met.
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS
PAGE
Report of Independent Registered Public Accounting Firm.....................58
Balance Sheet...............................................................59
Statement of Operations.....................................................60
Statement of Partners' Capital Accounts.....................................61
Statement of Cash Flows.....................................................62
Notes to Financial Statements...............................................63
57
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
ATLAS AMERICA SERIES 26-2005 L.P.
A DELAWARE LIMITED PARTNERSHIP
We have audited the accompanying balance sheet of Atlas America Series 26-2005
L.P. (a Delaware Limited Partnership) as of December 31, 2005, and the related
statement of operations, partners' capital, and cash flows for the period May
26, 2005 (date of formation) through December 31, 2005. 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 audits 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 26-2005
L.P. as of December 31, 2005, and the results of its operations and its cash
flows for the period May 26, 2005 (date of formation) through December 31, 2005
in conformity with accounting principles generally accepted in the United States
of America.
/s/ Grant Thornton LLP
Cleveland, Ohio
March 20, 2006 (except for Note 12, as to which the date is April 28, 2006)
58
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
BALANCE SHEET
DECEMBER 31, 2005
2005
-------------
ASSETS:
Current assets:
Cash and cash equivalents............................................................. $ 100
Accounts receivable-affiliate......................................................... 17,251,500
------------
Total current assets............................................................. 17,251,600
Oil and gas properties, well drilling contracts and leases, (successful efforts)....... 22,678,900
Less accumulated depletion........................................................... (7,600)
------------
22,671,300
------------
$ 39,922,900
============
LIABILITIES AND PARTNERS' CAPITALS
Current liabilities:
Accrued liabilities................................................................... $ 13,200
------------
Total current liabilities........................................................ 13,200
Asset retirement obligation........................................................... 567,900
Partners' capital:
Managing general partner.............................................................. 4,450,900
Investor partners (1400 units)........................................................ 34,890,900
------------
39,341,800
------------
$ 39,922,900
============
The accompanying notes are an integral part of these financial statements
59
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
STATEMENT OF OPERATIONS
FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005
2005
-------------
REVENUES:
Natural gas and oil sales................................................... $ 34,700
-------------
Total revenues........................................................ 34,700
COST AND EXPENSES:
Production expenses........................................................... 2,500
Depletion of oil and gas properties........................................... 7,600
General and administrative expenses........................................... 13,600
-------------
Total expenses.......................................................... 23,700
-------------
NET EARNINGS............................................................ $ 11,000
=============
ALLOCATION OF NET EARNINGS:
Managing general partner.................................................. $ 6,600
=============
Investor partners......................................................... $ 4,400
=============
Net earnings per investor partnership unit................................ $ 3
=============
The accompanying notes are an integral part of these financial statements
60
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
STATEMENT OF PARTNERS' CAPITAL ACCOUNTS
FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005
MANAGING
GENERAL INVESTOR
PARTNER PARTNERS TOTAL
------------------- ------------------- -----------------
BALANCE AT MAY 26, 2005 $ - $ - $ -
Partners' capital contributions
Cash.......................................................... 100 34,886,500 34,886,600
Syndication and offering costs................................ 4,535,200 - 4,535,200
Tangible equipment/leasehold costs............................ 4,444,200 - 4,444,200
--------------- --------------- ---------------
Total contributions........................................... 8,979,500 34,886,500 43,866,000
Syndication and offering costs, immediately charged to capital (4,535,200) - (4,535,200)
--------------- --------------- ---------------
4,444,300 34,886,500 39,330,800
Participation in revenue and costs and expenses
Net production revenues....................................... 12,300 19,900 32,200
Depletion..................................................... (500) (7,100) (7,600)
General and administrative.................................... (5,200) (8,400) (13,600)
--------------- --------------- ---------------
Net earnings.................................................. 6,600 4,400 11,000
--------------- --------------- ---------------
BALANCE AT DECEMBER 31, 2005 $ 4,450,900 $ 34,890,900 $ 39,341,800
=============== =============== ===============
The accompanying notes are an integral part of these financial statements
61
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
STATEMENT OF CASH FLOWS
FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005
2005
------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings.................................................................................... $ 11,000
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion..................................................................................... 7,600
Increases in accrued liabilities and accounts payable affiliate............................... 13,200
Increase in accounts receivable affiliate..................................................... (17,251,500)
------------------
Net cash used in operating activities......................................................... (17,219,700)
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas well drilling contracts paid to Managing General Partner............................ (17,666,800)
------------------
Net cash used in investing activities........................................................... (17,666,800)
CASH FLOWS FROM FINANCING ACTIVITIES:
Partners' capital contributions................................................................. 34,886,600
------------------
Net cash provided by financing activities 34,886,600
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.............................. $ 4,444,200
Syndication and offering costs.................................................................. 4,535,200
------------------
$ 8,979,400
==================
Asset retirement obligation..................................................................... $ 567,900
==================
The accompanying notes are an integral part of these financial statements
62
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 1 - NATURE OF OPERATIONS
Atlas America Series 26-2005 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 579
subscribers to units as either Limited Partners or Investor General Partners
depending upon their election. The Partnership was formed on May 26, 2005 to
drill and operate gas wells located primarily in Western Pennsylvania and
Tennessee. At December 31, 2005, the majority of the Partnership's properties
were scheduled for drilling. Recoverability of the cost of properties is
dependent on the results of such development activities.
SPIN-OFF OF ATLAS AMERICA, INC. FROM RESOURCE AMERICA, INC. ("RAI"). On
June 30, 2005, RAI distributed its remaining 10.7 million shares of Atlas
America, Inc. to its stockholders in the form of a tax-free dividend. Although
the distribution itself was tax-free to RAI's stockholders, as a result of the
deconsolidation there may be some tax liability arising from prior unrelated
corporate transactions among Atlas America, Inc. and some of its subsidiaries.
The Partnership does not anticipate that these transactions will have a direct
material impact on its financial position or results of operations. Atlas
America, Inc. (and the managing general partner) no longer consolidates its
federal return with RAI as of June 30, 2005.
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 ("U.S. GAAP").
Use of Estimates
Preparation of the financial statements in conformity with U.S. GAAP
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, costs and expenses during the reporting period. Actual results
could differ from these estimates.
63
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Receivables
In evaluating the need for an allowance for possible losses, Atlas
performs ongoing credit evaluations of its customers and adjusts credit limits
based upon payment history and the customers' current creditworthiness. Atlas
extends credit on an unsecured basis to many of its energy customers. At
December 31, 2005, Atlas' credit evaluation indicated that it and the
Partnership had no need for an allowance for possible losses.
Revenue Recognition
Revenues from sales of natural gas are recognized when the gas has been
delivered to the purchaser. Natural gas is sold under various contracts entered
into by the Partnership's managing general partner. Virtually all of the
managing general partner's contract pricing provisions are tied to a market
index, with certain adjustments based on, among other factors, whether a well
delivers to a gathering or transmission line, quality of natural gas and
prevailing supply and demand conditions, so that the price the Partnership
receives from the sale of natural gas fluctuates to remain competitive with
generally available natural gas supplies in the market.
Because there are timing differences between the delivery of natural gas
and oil and receipt of a delivery statement, the Partnership has unbilled
revenues. These revenues are accrued based on volumetric data and estimates of
the related transportation and compression fees which are, in turn, based on
applicable product prices. Unbilled trade receivables of $29,900 in the December
31, 2005 balance sheet are a component of "Accounts receivable - affiliate."
Recently Issued Financial Accounting Standards
In May 2005, the Financial Accounting Standards Board, ("FASB") issued
Statement No. 154, Accounting Changes and Error Corrections ("SFAS 154"). SFAS
154 requires retrospective application to prior periods' financial statements of
changes in an accounting principle. It also requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening balance
of retained earnings for that period rather than being reported in an income
statement. The statement will be effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
The impact of SFAS 154 will depend on the nature and extent of any voluntary
accounting changes and corrections of errors after the effective date, but
management does not currently expect SFAS 154 to have a material impact on the
Partnership's financial position or results of operations.
Fair Value of Financial Instruments
For cash, receivables and payables, the carrying amounts approximate fair
values because of the short maturities of these instruments.
64
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 2005
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Supplemental Cash Flow Information
The Partnership considers temporary investments with a maturity at the
date of acquisition of 90 days or less to be cash equivalents. No cash was paid
by the Partnership for interest or income taxes for the period ended December
31, 2005.
Concentration of Credit Risk
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, 2005, the Partnership had no deposits over the insurance limit for
the Federal Deposit Insurance Corporation. No losses have been experienced on
such investments.
Comprehensive Income
The Partnership is subject to the provisions of SFAS No. 130, "Reporting
Comprehensive Income," which requires disclosure of comprehensive income and its
components. Comprehensive income includes net income and all other changes in
equity of a business during a period from non-owner sources. These changes,
other than net income, are referred to as "other comprehensive income" which
includes changes in unrealized hedging gains and losses.
Property and Equipment
Property and equipment are stated at cost. Depletion is based on cost less
estimated salvage value primarily using the unit-of-production method over the
assets' estimated useful lives. Maintenance and repairs are expensed as
incurred. Major renewals and improvements that extend the useful lives of
property are capitalized.
Oil and gas properties consist of the following: AT DECEMBER 31,
2005
----------------
Mineral interest in properties:
Proved properties............................................. $839,900
Wells and related equipment................................... 21,839,000
----------------
22,678,900
Accumulated depletion:
Oil and gas properties........................................ (7,600)
----------------
$ 22,671,300
================
65
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Oil and Gas Properties
The Partnership uses the successful efforts method of accounting for oil
and gas producing activities. Costs to acquire mineral interests in oil and gas
properties and to drill and equip wells are capitalized. Oil is converted to gas
equivalent basis ("mcfe") at the rate of one barrel equals 6 mcf. Depletion is
provided on the units of production method.
The Partnership's long-lived assets are reviewed for impairment annually
for events or changes in circumstances that indicate that the carrying amount of
an asset may not be recoverable. Long-lived assets are reviewed for potential
impairments at the lowest levels for which there are identifiable cash flows
that are largely independent of other groups of assets. The review is done by
determining if the historical cost of proved properties less the applicable
accumulated depreciation, depletion and amortization and abandonment is less
than the estimated expected undiscounted future cash flows. The expected future
cash flows are estimated based on the Partnership's plans to continue to produce
and develop proved reserves. Expected future cash flow from the sale of
production of reserves is calculated based on estimated future prices. The
Partnership estimates prices based upon market related information including
published futures prices. The estimated future level of production is based on
assumptions surrounding future levels of prices and costs, field decline rates,
market demand and supply, and the economic and regulatory climates. If the
carrying value exceeds such cash flows, an impairment loss is recognized for the
difference between the estimated fair market value (as determined by discounted
future cash flows), and the carrying value of the assets.
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. Upon the sale of an
entire interest in an unproved property where the property had been assessed for
impairment individually, a gain or loss is recognized in the statement of
operations. If a partial interest in an unproved property is sold, any funds
received are accounted for as a reduction of the cost in the interest retained.
Asset Retirement Obligation
The fair values of asset retirement obligations are recognized in the
period they are incurred if a reasonable estimate of fair value can be made.
Asset retirement obligations primarily relate to the abandonment of oil and gas
producing facilities and include costs to dismantle and relocate or dispose of
production equipment, gathering systems, wells and related structures. Estimates
are based on historical experience of the Partnership's managing general partner
in plugging and abandoning wells, estimated remaining lives of those wells based
on reserve estimates, external estimates as to the cost to plug and abandon the
wells in the future and federal and state regulatory requirements. The
Partnership does not provide for a market risk premium associated with asset
retirement obligation because a reliable estimate cannot be determined.
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.
66
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Environmental Matters (Continued)
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, 2005, 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, 2005, sales to U S Energy
Exploration Corporation, Dominion Field Services, Inc., and Amerada Hess
Corporation accounted for 66%, 23%, 11%, respectively of total revenues. No
other customer accounted for 10% or more of total revenues for the period
ended December 31, 2005.
Derivative Instruments
The Partnership applies the provisions of SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activity" ("SFAS No. 133"). SFAS No.
133 requires each derivative instrument to be recorded in the balance sheet
as either an asset or liability measured at fair value. Changes in a
derivative instrument's fair value will be recognized currently in earnings
unless specific hedge accounting criteria are met.
NOTE 3 - ASSET RETIREMENT OBLIGATION
The Partnership accounts for its estimated plugging and abandonment
of its oil and gas properties in accordance with SFAS 143, "Accounting for
Asset Retirement Obligations".
A reconciliation of the Partnership's liability for well plugging and
abandonment costs for the period ended December 31, 2005 is as follows:
2005
---------------
Asset retirement obligation, at beginning of period................. $ -
Liabilities incurred from drilling wells............................ 567,900
---------------
Asset retirement obligation, at end of period....................... $ 567,900
===============
NOTE 4 - 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.
67
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 5 - 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................................................... 74.18% 25.82%
NOTE 5 - PARTICIPATION IN REVENUES AND COSTS (CONTINUED)
------------------
(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 40%.
(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 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The Partnership has entered into the following significant transactions
with Atlas Resources, Inc. ("Atlas"), the Managing General Partner, and its
affiliates as provided under the Partnership agreement:
68
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (CONTINUED)
Drilling contracts to drill and complete wells for the Partnership are
charged at cost plus 15%. The cost of the wells includes reimbursement to Atlas
of its general and administrative overhead cost ($14,307 per well) and all
ordinary and actual costs of drilling, testing and completing the wells. The
Partnership paid $34,886,500 to Atlas in 2005 under the drilling contract, of
which $17,666,800 had been spent as of December 31, 2005 on well drilling costs
and the remaining balance of $17,219,700 is shown as part of accounts
receivable-affiliate, due from Atlas, on the Partnership's balance sheet.
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 $839,900.
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 2005 were $400.
Monthly well supervision fees which are included in production expenses in
the Statement of Operations are payable to Atlas at $285 per well per month for
operating and maintaining the wells. Well supervision fees incurred in 2005 were
$1,400.
Transportation fees which are included in production expenses in the
Statement of Operations are payable to Atlas at competitive rates in the primary
and secondary drilling areas. Transportation costs incurred in 2005 were $400.
The Managing General Partner and its affiliates will be reimbursed for all
direct costs expended on the Partnership's behalf. For the year ended December
31, 2005, the Partnership reimbursed the Managing General Partner $13,900 for
direct costs.
Atlas and Anthem Securities, an affiliate of Atlas, received $4,535,200 in
2005 for fees, commissions and reimbursements as dealer-manager and to organize
the Partnership.
As the Managing General Partner, Atlas performs all administrative and
management functions for the Partnership including billing revenues and paying
expenses. Accounts receivable - affiliate on the Partnership's Balance Sheet
represents the net production revenues due from Atlas.
NOTE 7 - COMMITMENTS
Subject to certain conditions, investor partners may present their
interests beginning in 2010 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 5% 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.
69
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 7 - COMMITMENTS (CONTINUED)
Beginning one year after each of the Partnership's wells has been placed
into production the managing general partner, as operator, may retain $200 of
the Partnership's revenues per month to cover the estimated future plugging and
abandonment costs. As of December 31, 2005 the managing general partner had not
withheld such funds.
NOTE 8 - 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. In
2005, Atlas was not required to subordinate any of its revenues to the investor
Partners.
NOTE 9 - DERIVATIVE INSTRUMENTS
Atlas on behalf of the Partnership from time to time enters into natural
gas futures and option contracts to hedge exposure to changes in natural gas
prices. At any point in time, such contracts may include regulated New York
Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. NYMEX
contracts are generally settled with offsetting positions, but may be settled by
the delivery of natural gas.
Atlas formally documents all relationships between hedging instruments
and the items being hedged, including Atlas's risk management objective and
strategy for undertaking the hedging transactions. This includes matching the
natural gas futures and options contracts to the forecasted transactions. Atlas
assesses, both at the inception of the hedge and on an ongoing basis, whether
the derivatives are highly effective in offsetting changes in the fair value of
hedged items. Historically these contracts have qualified and been designated as
cash flow hedges and recorded at their fair values. Gains or losses on future
contracts are determined as the difference between the contract price and a
reference price, generally prices on NYMEX. Changes in fair value are recognized
in Partners' Capital as Accumulated Other Comprehensive Income (Loss) and
recognized within the statement of operations in the month the hedged gas is
sold. If it is determined that a derivative is not highly effective as a hedge
or it has ceased to be a highly effective hedge, due to the loss of correlation
between changes in gas reference prices under a hedging instrument and actual
gas prices, Atlas will discontinue hedge accounting for the derivative and
subsequent changes in fair value for the derivative will be recognized
immediately into earnings. At December 31, 2005, the Partnership had no open
natural gas futures contracts related to natural gas sales and accordingly, had
no unrealized gain or loss related to open NYMEX contracts at that date.
70
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 10 - 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 11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
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 RELATED TO OIL AND GAS PRODUCING ACTIVITIES
The following table presents the capitalized costs related to natural
gas and oil producing activities at December 31:
2005
--------------
Mineral interest in properties - proved properties................. $ 839,900
Wells and related equipment........................................ 21,839,000
Accumulated depletion.............................................. (7,600)
-------------
NET CAPITALIZED COSTS $ 22,671,300
=============
(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 period ended December 31:
2005
---------------
Natural gas and oil sales............................................... $ 34,700
Production costs........................................................ (2,500)
Depletion............................................................... (7,600)
---------------
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES......... $ 24,600
===============
71
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
(3) COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
Costs incurred for the period ended December 31, are as follows:
2005
------------
Capitalized asset retirement obligation.................................. $ 567,900
Acquisition costs........................................................ 839,900
Tangible equipment and drilling costs.................................... 21,271,100
------------
TOTAL COSTS INCURRED................................................. $ 22,678,900
============
(4) OIL AND GAS RESERVE INFORMATION
The information presented below represents estimates of proved natural gas
and oil reserves. The estimates of the Partnership's proved gas reserves are
based upon evaluations made by management and verified by Wright & Company,
Inc., an independent petroleum engineering firm, as of December 31, 2005. All
reserves are located within the United States. Reserves are estimated in
accordance with guidelines established by the Securities and Exchange Commission
and the Financial Accounting Standards Board which require that reserve
estimates be prepared under existing economic and operating conditions with no
provision for price and cost escalation except by contractual arrangements.
Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e. prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.
Proved developed reserves are those which are expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as "proved developed reserves"
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved. All reserves are proved developed reserves and are located in the
Appalachian Basin area.
72
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2005
NOTE 11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measures of discounted future net cash flows may not represent the fair market
value of the Partnership's oil and gas reserves or the present value of future
cash flows of equivalent reserves, due to anticipated future changes in oil and
gas prices and in production and development costs and other factors for which
effects have not been provided.
NATURAL
GAS OIL
(MCF) (BBLS)
---------- --------
Proved developed reserves:
Beginning of period.................... - -
Proved developed reserves.............. 8,289,000 -
Production............................. (3,100) -
---------- --------
BALANCE, DECEMBER 31, 2005 8,285,900 -
========== ========
NOTE 12 - SUBSEQUENT EVENTS
Atlas America, Inc. recently announced that it intends to transfer into a
wholly-owned limited liability company or limited partnership subsidiary of
Atlas America, Inc. substantially all of its natural gas and oil exploration and
production assets. As part of that transaction, in March 2006, Atlas Resources,
Inc. was merged into a newly-formed limited liability company, Atlas Resources,
LLC, which Atlas America, Inc. anticipates will become an indirect subsidiary of
Atlas America's newly-formed subsidiary. Atlas Resources, LLC, however, will
continue to serve as the Partnership's managing general partner, and does not
expect that any of these transactions will have a material effect on the
Partnership's financial position or results of operations. Atlas America, Inc.
further intends to make a registered initial public offering of a minority
interest, estimated to be 20%, in its newly-formed subsidiary.
73
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS
(a) The following documents are filed as part of this Form 10:
1. FINANCIAL STATEMENTS
The financial statements of Atlas America Series 26-2005 L.P. as
of December 31, 2005 are set forth in Item 13 "Financial
Statements and Supplementary Data."
2. EXHIBITS
EXHIBIT NO. DESCRIPTION
----------- -----------
4.1 Certificate of Limited Partnership for Atlas America Series 26-2005 L.P.
4.2 Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 26-2005 L.P.
10.1 Drilling and Operating Agreement for Atlas America Series 26-2005 L.P.
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.
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.
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
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.
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
10.7 Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc.
and Viking Resources Corp.
10.8 Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp.
10.9 Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc.
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
10.11 Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy Services, Inc.
d/b/a GASMARK
10.12 Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp.
10.13 Drilling and Operating Agreement Dated September 15, 2004 by and between Atlas America, Inc. and Knox Energy,
LLC
10.14 Dealer-Manager Agreement for Anthem Securities, Inc.
__________________________________
74
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange
Act of 1934, the registrant has duly caused this registration statement to be
signed on its behalf by the undersigned, thereunto duly authorized.
ATLAS AMERICA SERIES 26-2005 L.P.
(Registrant)
By: Atlas Resources, LLC
Managing General Partner
Date: April 28, 2006 By: /s/ Freddie Kotek
---------------------------------------
Freddie Kotek, Chairman of the Board of
Directors, Chief Executive Officer and
President
75
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
----------- -----------
4.1 Certificate of Limited Partnership for Atlas America Series 26-2005 L.P.
4.2 Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 26-2005 L.P.
10.1 Drilling and Operating Agreement for Atlas America Series 26-2005 L.P.
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.
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.
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
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.
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
10.7 Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc.
and Viking Resources Corp.
10.8 Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp.
10.9 Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc.
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
10.11 Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy Services, Inc.
d/b/a GASMARK
10.12 Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp.
10.13 Drilling and Operating Agreement Dated September 15, 2004 by and between Atlas America, Inc. and Knox Energy,
LLC
10.14 Dealer-Manager Agreement for Anthem Securities, Inc.
__________________________________