0000950123-11-097520.txt : 20111110
0000950123-11-097520.hdr.sgml : 20111110
20111110154056
ACCESSION NUMBER: 0000950123-11-097520
CONFORMED SUBMISSION TYPE: 10-Q
PUBLIC DOCUMENT COUNT: 11
CONFORMED PERIOD OF REPORT: 20110930
FILED AS OF DATE: 20111110
DATE AS OF CHANGE: 20111110
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: Atlas America Series 26-2005 L.P.
CENTRAL INDEX KEY: 0001342514
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 000000000
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-Q
SEC ACT: 1934 Act
SEC FILE NUMBER: 000-51945
FILM NUMBER: 111195143
BUSINESS ADDRESS:
STREET 1: WESTPOINTE CORPORATE CENTER ONE
STREET 2: 1550 CORAOPOLIS HEIGHTS RD. 2ND. FLOOR
CITY: MOON TOWNSHIP
STATE: PA
ZIP: 15108
BUSINESS PHONE: 330-896-8510
MAIL ADDRESS:
STREET 1: WESTPOINTE CORPORATE CENTER ONE
STREET 2: 1550 CORAOPOLIS HEIGHTS RD. 2ND. FLOOR
CITY: MOON TOWNSHIP
STATE: PA
ZIP: 15108
10-Q
1
c23888e10vq.htm
FORM 10-Q
Form 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 000-51945
ATLAS AMERICA SERIES 26-2005 L.P.
(Name of small business issuer in its charter)
Delaware
20-2879859
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA
15108
(Address of principal executive offices)
(zip code)
Issuers telephone number, including area code: (412) 262-2830
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer, non accelerated filer and smaller reporting company in Rule 12b-2
of the Exchange Act (Check one):
Large accelerated filer o
Accelerated filer o
Non-accelerated filer o
Smaller reporting company þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
ATLAS AMERICA SERIES 26-2005 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
NOTE 1 - DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Atlas America Series 26-2005 L.P. (the Partnership) is a Delaware limited partnership and
formed on May 26, 2005 with Atlas Resources, LLC serving as its Managing General Partner and
operator (Atlas Resources or MGP). Atlas Resources is an indirect subsidiary of Atlas Energy,
L.P., formerly Atlas Pipeline Holdings, L.P. (Atlas Energy) (NYSE: ATLS). On February 17, 2011,
Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general
partner of Atlas Pipeline Partners, L.P. (APL) (NYSE: APL), completed an acquisition of assets
from Atlas Energy, Inc., which included its investment partnership business; its oil and gas
exploration, development and production activities conducted in Tennessee, Indiana, and Colorado,
certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania
and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P.
and related entities (the Transferred Business).
Atlas Energy recently announced that it intends to create a newly formed exploration and
production master limited partnership named Atlas Resource Partners, L.P. (Atlas Resource
Partners), which will hold substantially all of ATLS current natural gas and oil development and
production assets and the partnership management business.
Atlas Resources focus is on the development and/or production of natural gas and oil in the
Appalachian, Michigan, Indiana and/or Colorado basin regions of the United States of America. Atlas
Resources is also a leading sponsor of and manages tax-advantaged direct investment partnerships,
in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy
Resource Services, Inc. provides Atlas Resources with the personnel necessary to manage its assets
and raise capital.
The accompanying financial statements, which are unaudited except that the balance sheet at
December 31, 2010 is derived from audited financial statements, are presented in accordance with
the requirements of Form 10-Q and accounting principles generally accepted in the United States of
America (U.S. GAAP) for interim reporting. They do not include all disclosures normally made in
financial statements contained in the Form 10-K. These interim financial statements should be read
in conjunction with the audited financial statements and notes thereto presented in the
Partnerships Annual Report on Form 10-K for the year ended December 31, 2010. The results of
operations for the three and nine months ended September 30, 2011 may not necessarily be indicative
of the results of operations for the year ended December 31, 2011.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In managements opinion, all adjustments necessary for a fair presentation of the
Partnerships financial position, results of operations and cash flows for the periods disclosed
have been made.
In addition to matters discussed further in this note, the Partnerships significant
accounting policies are detailed in its audited financial statements and notes thereto in the
Partnerships annual report on Form 10-K for the year ended December 31, 2010 filed with the
Securities and Exchange Commission (SEC).
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Use of Estimates
Preparation of 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 that exist at the date of the Partnerships financial statements, as well as the
reported amounts of revenue and costs and expenses during the reporting periods. The Partnerships
financial statements are based on a number of significant estimates, including the revenue and
expense accruals, depletion, asset impairments, fair value of derivative instruments and the
probability of forecasted transactions. Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions
as much as 60 days after the month of delivery. Consequently, the most recent two months financial
results were recorded using estimated volumes and contract market prices. Differences between
estimated and actual amounts are recorded in the following months financial results. Management
believes that the operating results presented for the three and nine months ended September 30,
2011 and 2010 represent actual results in all material respects (see Revenue Recognition
accounting policy for further description).
Accounts Receivable and Allowance for Possible Losses
In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit
evaluations of the Partnerships customers and adjusts credit limits based upon payment history and
the customers current creditworthiness, as determined by review of the Partnerships customers
credit information. Credit is extended on an unsecured basis to many of its energy customers. As of
September 30, 2011 and December 31, 2010, the MGPs credit evaluation indicated that the
Partnership had no need for an allowance for possible losses.
Oil and Gas Properties
Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred.
Major renewals and improvements that extend the useful lives of property are capitalized. The
Partnership follows the successful efforts method of accounting for oil and gas producing
activities. Oil is converted to gas equivalent basis (Mcfe) at the rate of one barrel equals six
Mcf.
The Partnerships depletion expense is determined on a field-by-field basis using the
units-of-production method. Depletion rates for lease, well and related equipment costs are based
on proved developed reserves associated with each field. Depletion rates are determined based on
reserve quantity estimates and the capitalized costs of developed producing properties. Upon the
sale or retirement of a complete field of a proved property, the Partnership eliminates the cost
from the property accounts and the resultant gain or loss is reclassified to the Partnerships
statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds
to accumulated depreciation and depletion within its balance sheets.
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil and Gas Properties (Continued)
September 30,
December 31,
2011
2010
Proved properties:
Leasehold interests
$
1,110,900
$
1,110,900
Wells and related equipment
44,068,700
44,061,200
45,179,600
45,172,100
Accumulated depletion
(35,911,200
)
(35,247,800
)
Oil and gas properties
$
9,268,400
$
9,924,300
Impairment of Long-Lived Assets
The Partnership reviews its long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be recoverable. If it is
determined that an assets estimated future cash flows will not be sufficient to recover its
carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset
to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Partnerships oil and gas properties is done on a field-by-field basis by
determining if the historical cost of proved properties, less the applicable accumulated depletion,
and abandonment is less than the estimated expected undiscounted future cash flows. The expected
future cash flows are estimated based on the Partnerships 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 current contracts in
place, adjusted for basis differentials and market related information including published futures
prices. The estimated future level of production is based on assumptions surrounding future prices
and costs, field decline rates, market demand and supply and the economic and regulatory climates.
If the carrying value exceeds the expected future 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.
The determination of oil and natural gas reserve estimates is a subjective process and the
accuracy of any reserve estimate depends on the quality of available data and the application of
engineering and geological interpretation and judgment. Estimates of economically recoverable
reserves and future net cash flows depend on a number of variable factors and assumptions that are
difficult to predict and may vary considerably from actual results. In addition, reserve estimates
for wells with limited or no production history are less reliable than those based on actual
production. Estimated reserves are often subject to future revisions, which could be substantial,
based on the availability of additional information which could cause the assumptions to be
modified. The Partnership cannot predict what reserve revisions may be required in future periods.
There was no impairment charges recognized during the three and nine months ended September 30,
2011 or for the year ended December 31, 2010.
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Working Interest
The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP
and limited partners based on their ratio of capital contributions to total contributions (working
interest). The MGP is also provided an additional working interest of 7% as provided in the
Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all
drilling costs, estimated working interest percentage ownership rates are utilized to allocate
revenues and expenses until the wells are completely drilled and turned on-line into production.
Once the wells are completed, the final working interest ownership of the partners is determined
and any previously allocated revenues and expenses based on the estimated working interest
percentage ownership are adjusted to conform to the final working interest percentage ownership.
Revenue Recognition
The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue
is recognized when produced quantities are delivered to a custody transfer point, persuasive
evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the
purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales
price is fixed or determinable. Revenues from the production of natural gas and crude oil in which
the Partnership has an interest with other producers are recognized on the basis of the
Partnerships percentage ownership of working interest. Generally, the Partnerships sales
contracts are based on pricing provisions that are tied to a market index with certain adjustments
based on proximity to gathering and transmission lines and the quality of its natural gas.
The Partnership accrues unbilled revenue due to timing differences between the delivery of
natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded
based upon volumetric data from the Partnerships records and management estimates of the related
commodity sales and transportation fees which are, in turn, based upon applicable product prices
(see Use of Estimates accounting policy for further description). The Partnership had unbilled
revenues at September 30, 2011 and December 31, 2010 of $256,200 and $291,400, respectively, which
are included in accounts receivable affiliate within the Partnerships balance sheets.
Recently Issued Accounting Standards
In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update
2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to
present the total of comprehensive income, the components of net income, and the components of
other comprehensive income in either a single continuous statement of comprehensive income or in
two separate but consecutive statements. In both choices, an entity is required to present each
component of net income along with a total net income, each component of other comprehensive
income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to
present the components of other comprehensive income as part of the statement of changes in
partners capital. These changes apply to both annual and interim financial statements. Update
2011-05 will be effective for public entities fiscal years, and interim periods within those
years, beginning after December 15, 2011. The Partnership will apply the requirements of Update
2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material
impact on its financial position, results of operations or related disclosures.
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 3 ASSET RETIREMENT OBLIGATION
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil
and gas wells and related facilities. It also recognizes a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be made. The
associated asset retirement costs are capitalized as part of the carrying amount of the long-lived
asset. The Partnership also considers the estimated salvage value in the calculation of depletion.
The estimated liability is based on the MGPs historical experience 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 liability is discounted using an assumed credit-adjusted risk-free interest rate.
Revisions to the liability could occur due to changes in estimates of plugging and abandonment
costs or remaining lives of the wells or if federal or state regulators enact new plugging and
abandonment requirements. The Partnership has no assets legally restricted for purposes of settling
asset retirement obligations. Except for its oil and gas properties, the Partnership has determined
that there are no other material retirement obligations associated with tangible long-lived assets.
A reconciliation of the Partnerships liability for plugging and abandonment costs for the
periods indicated is as follows:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2011
2010
2011
2010
Asset retirement obligation at beginning of period
$
1,936,600
$
1,526,200
$
1,880,200
$
1,497,600
Liabilities settled
(16,300
)
Accretion expense
28,200
22,600
84,600
67,500
Asset retirement obligation at end of period
$
1,964,800
$
1,548,800
$
1,964,800
$
1,548,800
NOTE 4 DERIVATIVE INSTRUMENTS
The MGP, on behalf of the Partnership, historically used a number of different derivative
instruments, principally swaps and collars, in connection with its commodity price risk management
activities. The MGP entered into financial instruments to hedge the Partnerships forecasted
natural gas and crude oil against the variability in expected future cash flows attributable to
changes in market prices. Swap instruments are contractual agreements between counterparties to
exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap
agreements, the Partnership received or paid a fixed price and received or remitted a floating
price based on certain indices for the relevant contract period. Commodity-based option instruments
are contractual agreements that grant the right, but not obligation, to purchase or sell natural
gas and crude oil at a fixed price for the relevant contract period.
Historically, the MGP has entered into natural gas and crude oil future option contracts and
collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its
exposure to changes in natural gas and oil prices. At any point in time, such contracts included
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. Crude oil
contracts are based on a West Texas Intermediate (WTI) index. These contracts qualified and were
designated as cash flow hedges and recorded at their fair values.
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 4 DERIVATIVE INSTRUMENTS (Continued)
The MGP formally documented all relationships between hedging instruments and the items being
hedged, including its risk management objective and strategy for undertaking the hedging
transactions. This included matching the commodity derivative contracts to the forecasted
transactions. The MGP assessed, both at the inception of the derivative and on an ongoing basis,
whether the derivative was effective in offsetting changes in the forecasted cash flow of the
hedged item. If it determined that a derivative was not effective as a hedge or that it had ceased
to be an effective hedge due to the loss of adequate correlation between the hedging instrument and
the underlying item being hedged, the MGP discontinued hedge accounting for the derivative and
subsequent changes in the derivative fair value, which was determined by the MGP through the
utilization of market data, were recognized immediately within gain (loss) on mark-to-market
derivatives in the Partnerships statements of operations. For derivatives qualifying as hedges,
the Partnership recognized the effective portion of changes in fair value in partners capital as
accumulated other comprehensive income and reclassified the portion relating to commodity
derivatives to gas and oil production revenues for the Partnerships derivatives within the
Partnerships statements of operations as the underlying transactions were settled. For
non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the
Partnership recognized changes in fair value within gain (loss) on mark-to-market derivatives in
its statements of operations as they occurred.
Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy monetized its
derivative instruments related to the Transferred Business. The monetized proceeds related to
instruments that were originally put into place to hedge future natural gas and oil production of
the Transferred Business, including production generated through its drilling partnerships. At
September 30, 2011, the Partnership recorded a net receivable from the monetized derivative
instruments of $239,000 in accounts receivable-affiliate and $182,000 in long-term
receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive
income on the Partnerships balance sheets, which will be allocated to natural gas and oil
production revenue generated over the period of the original instruments term. As a result of the
monetization and the early settlement of natural gas and oil derivative instruments and the
unrealized gains recognized in income in prior periods due to natural gas and oil property
impairments, the Partnership recorded a net deferred gain on its balance sheets in other
comprehensive income of $307,600 as of September 30, 2011. Unrealized gains, net of the MGPs
interest, previously recognized into income as a result of prior period impairments included in
accumulated other comprehensive income were $113,400. The MGPs portion of the unrealized gains was
written-off as part of the terms related to the acquisition of the Transferred Business. For the
three and nine months ended September 30, 2011, the Partnership reclassified $106,000 of unrealized
gains previously recognized into income from prior period impairments related to the MGP from a
hedge receivable due from affiliate to a non-cash distribution to the MGP. As such, $106,000 was
recorded as a distribution to partners on the statement of changes in partners capital. During the
nine months ended September 30, 2011, $176,900 of monetized proceeds were recorded by the
Partnership and allocated only to the limited partners. Of the remaining $307,600 of net unrealized
gain in accumulated other comprehensive income, the Partnership will reclassify $158,000 of net
gains to the Partnerships statements of operations over the next twelve month period and the
remaining $149,600 in later periods.
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 4 DERIVATIVE INSTRUMENTS (Continued)
The following tables summarize the fair value of the Partnerships derivative instruments as
of December 31, 2010, as well as the gain or loss recognized in the statements of operations for
the three and nine months ended September 30, 2011 and 2010:
Fair Value of Derivative Instruments:
Fair Value
Balance Sheet
December 31,
Derivatives in Cash Flow Hedging Relationships
Location
2010
Commodity Contracts
Current assets
$
407,600
Long-term assets
399,000
806,600
Current liabilities
(7,700
)
Long-term liabilities
(74,700
)
(82,400
)
Total
$
724,200
Effects of Derivative Instruments on Statement of Operations:
Three Months Ended
Nine Months Ended
September 30,
September 30,
September 30,
September 30,
2011
2010
2011
2010
Derivative in Cash Flow
Gain Recognized in
Hedging Relationships
OCI on Derivatives
Commodity Contracts
$
$
403,400
$
17,700
$
962,600
Three Months Ended
Nine Months Ended
September 30,
September 30,
September 30,
September 30,
2011
2010
2011
2010
Location of Gain
Gain Reclassified from
Reclassified from
OCI into Net Loss (Income)
Accumulated
OCI into (Loss) Income
Gas and Oil Revenue
$
53,300
$
83,000
$
261,000
$
246,900
NOTE 5 COMPREHENSIVE (LOSS) INCOME
Comprehensive (loss) income includes net (loss) income and all other changes in the equity of
a business during a period from transactions and other events and circumstances from non-owner
sources that, under accounting principles generally accepted in the United States of America, have
not been recognized in the calculation of net (loss) income. These changes, other than net (loss)
income, are referred to as other comprehensive (loss) income and for the Partnership includes
changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges, and
changes in the estimated amount of future monetized proceeds to be received (See Note 4).
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 5 COMPREHENSIVE (LOSS) INCOME (Continued)
The monetized proceeds included in accounts receivable affiliate have been allocated to the Partnership
based on estimated future production in relation to all other partnerships future production
eligible to receive monetized hedge proceeds. As actual production is realized, there may be a
corresponding difference in the Partnerships actual share of monetized hedge proceeds received
than what was previously estimated. This component is shown as Difference in estimated monetized
gains receivable. The following table sets forth the calculation of the Partnerships
comprehensive (loss) income:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2011
2010
2011
2010
Net (loss) income
$
(49,800
)
$
(54,100
)
$
(135,400
)
$
(42,400
)
Other comprehensive (loss) income:
Unrealized holding (loss) gain
on hedging contracts
403,400
17,700
962,600
MGP portion of non-cash loss on
hedge instruments
106,000
Difference in estimated
monetized gains receivable
5,000
18,800
Less: reclassification
adjustment for (gains) losses
realized in net earnings (loss)
(53,300
)
(83,000
)
(261,000
)
(246,900
)
Total other comprehensive (loss) income
(48,300
)
320,400
(118,500
)
715,700
Comprehensive (loss) income
$
(98,100
)
$
266,300
$
(253,900
)
$
673,300
NOTE 6 FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership has established a hierarchy to measure its financial instruments at fair value
which requires it to maximize the use of observable inputs and minimize the use of unobservable
inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to
measure fair value:
Level 1 Quoted prices in active markets for identical assets and liabilities that the
reporting entity has the ability to access at the measurement date.
Level 2 Inputs other than quoted prices included within Level 1 that are observable for the
asset and liability or can be corroborated with observable market data for substantially the entire
contractual term of the asset or liability.
Level 3 Unobservable inputs that reflect the entities own assumptions about the assumptions
that market participants would use in the pricing of the asset or liability and are consequently
not based on market activity, but rather through particular valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership used a fair value methodology to value the assets and liabilities for its
outstanding derivative contracts (see Note 4). The Partnerships commodity derivative contracts
were valued based on observable market data related to the change in price of the underlying
commodity and are therefore defined as Level 2 fair value measurements.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs
based on discounted cash flow projections using numerous estimates, assumptions and judgments
regarding such factors at the date of establishment of an asset retirement obligation such as:
amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and
estimated inflation rates (see Note 3).
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 7 - TRANSACTIONS WITH ATLAS RESOURCES, LLC, AND ITS AFFILIATES
The Partnership has entered into the following significant transactions with the MGP and its
affiliates as provided under its Partnership Agreement:
Administrative costs which are included in general and administrative expenses in the
Partnerships statements of operations are payable at $75 per well per month.
Administrative costs incurred for the three and nine months ended September 30, 2011
were $26,400 and $78,300, respectively. Administrative costs incurred for the three and
nine months ended September 30, 2010 were $27,500 and $81,900, respectively.
Monthly well supervision fees which are included in production expenses in the
Partnerships statements of operations are payable at $318 per well per month in 2011
and 2010, for operating and maintaining the wells. Well supervision fees incurred for
the three and nine months ended September 30, 2011 were $110,700 and $327,500,
respectively. Well supervision fees incurred for the three and nine months ended
September 30, 2010 were $115,000 and $342,300, respectively.
Transportation fees which are included in production expenses in the Partnerships
statements of operations are generally payable at 13% of the natural gas sales price.
Transportation fees incurred for the three and nine months ended September 30, 2011 were
$58,700 and $156,400, respectively. Transportation fees incurred for the three and nine
months ended September 30, 2010 were $66,100 and $223,600, respectively.
The MGP and its affiliates perform all administrative and management functions for the
Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the
Partnerships Balance Sheets represents the net production revenues due from the MGP.
Subordination by Managing General Partner
Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50%
of its share of net production revenues of the Partnership to provide a distribution to the limited
partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a
cumulative basis, in each of the first five years of Partnership operations, commencing with the
first distribution of net revenues to the limited partners (September 2006). The MGP subordinated
$36,700 and $165,800 of its net production revenue to the limited partners for the nine months
ended September 30, 2011 and 2010, respectively.
ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)
NOTE 8 SUBSEQUENT EVENTS
Management has considered for disclosure any material subsequent events through the date the
financial statements were issued.
Formation of Atlas Resource Partners, L.P. On October 17, 2011, Atlas Energy announced that
its board of directors has approved a plan to create a newly formed exploration and production
master limited partnership named Atlas Resource Partners, L.P. (Atlas Resource Partners), which
will hold substantially all of Atlas Energys current natural gas and oil development, and
production assets and the partnership management business, including the MGP. Upon consummation of
the transaction, Atlas Energy will retain a 78.4% limited partner interest in Atlas Resource
Partners and intends to distribute a 19.6% limited partner interest in Atlas Resource Partners to
Atlas Energy unit holders. Atlas Energy will also own the newly created general partner of Atlas
Resource Partners, which will own a 2% general partner interest and all of the incentive
distribution rights in the newly formed partnership. Completion of the transaction is subject to a
number of conditions, including final approval by the Atlas Energys board of directors, as well as
the effectiveness of a Form 10 registration statement that Atlas Resource Partners filed with the
SEC on October 17, 2011. The transaction is expected to close in the first quarter of 2012. The MGP
anticipates that this transaction will have no impact on the Partnerships operations.
ITEM 2.
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (UNAUDITED)
Forward-Looking Statements
When used in this Form 10-Q, the words believes, anticipates, expects and similar
expressions are intended to identify forward-looking statements. These risks and uncertainties
could cause actual results to differ materially from the results stated or implied in this
document. Readers are cautioned not to place undue reliance on these forward-looking statements,
which speak only as of the date hereof. We undertake no obligation to publicly release the results
of any revisions to forward-looking statements which we may make to reflect events or circumstances
after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.
Managements Discussion and Analysis should be read in conjunction with our Financial
Statements and the Notes to our Financial Statements.
Overview
The following discussion provides information to assist in understanding our financial
condition and results of operations. Our operating cash flows are generated from our wells, which
produce primarily natural gas, but also some oil. Our produced natural gas and oil is then
delivered to market through affiliated or third-party gas gathering systems. Our ongoing operating
and maintenance costs have been and are expected to be fulfilled through revenues from the sale of
our natural gas and oil production. We pay our managing general partner (MGP), as operator, a
monthly well supervision fee, which covers all normal and regularly recurring operating expenses
for the production and sale of natural gas and oil such as:
well tending, routine maintenance and adjustment;
reading meters, recording production, pumping, maintaining appropriate books and
records; and
preparation of reports for us and 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 pay cost for
third-party services, materials, and a competitive charge for services performed directly by our
MGP or its affiliates. Also, beginning one year after each of our wells has been placed into
production, our MGP, as operator, may retain $200 per month, per well to cover the estimated future
plugging and abandonment costs of the well. As of September 30, 2011, our MGP had not withheld any
funds for this purpose. Our MGP intends to produce our wells until they are depleted or become
uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells
will be drilled and no additional funds will be required for drilling.
The availability of a ready market for natural gas and oil produced by us, and the price
obtained, depends on numerous factors beyond our control, including the extent of domestic
production, imports of foreign natural gas and oil, political instability or terrorist acts in oil
and gas producing countries and regions, market demand, competition from other energy sources, the
effect of federal regulation on the sale of natural gas and oil in interstate commerce, other
governmental regulation of the production and transportation of natural gas and oil and the
proximity, availability and capacity of pipelines and other required facilities. Our MGP is
responsible for selling our production. During 2011 and 2010, we experienced no problems in selling
our natural gas and oil. Product availability and price are the principal means of competition in
selling natural gas and oil production. While it is impossible to accurately determine our
comparative position in the industry, we do not consider our operations to be a significant factor
in the industry.
We have drilled and currently operate wells located in Pennsylvania and Tennessee. We have no
employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas
Energy Holdings Operating Company, LLC, for administrative services.
Results of Operations
The following table sets forth information relating to our production revenues, volumes, sales
prices, production costs and depletion during the periods indicated:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2011
2010
2011
2010
Production revenues (in thousands):
Gas
$
441
$
472
$
1,200
$
1,615
Oil
65
38
185
145
Total
$
506
$
510
$
1,385
$
1,760
Production volumes:
Gas (mcf/day) (1)
920
885
809
974
Oil (bbls/day) (1)
9
7
8
8
Total (mcfe/day) (1)
974
927
857
1,022
Average sales prices: (2)
Gas (per mcf) (1) (3)
$
5.57
$
6.81
$
5.75
$
6.97
Oil (per bbl) (1) (4)
$
85.45
$
72.44
$
89.50
$
73.85
Average production costs:
As a percent of revenues
46
%
49
%
47
%
44
%
Per mcfe (1)
$
2.59
$
2.92
$
2.77
$
2.78
Depletion per mcfe
$
2.85
$
3.01
$
2.84
$
3.00
(1)
Mcf represents thousand cubic feet, mcfe represents thousand cubic feet
equivalent, and bbls represents barrels. Bbls are converted to mcfe using the ratio
of six mcfs to one bbl.
(2)
Average sales prices represent accrual basis pricing after reversing the effect
of previously recognized gains resulting from prior period impairment charges.
Average gas prices are calculated by including in total revenue derivative gains
previously recognized into income (loss) and dividing by the total volume for the
period. Previously recognized derivative gains were $31,200 and $82,800 for the three
months ended September 30, 2011 and 2010, respectively. Previously recognized
derivative gains were $69,900 and $240,400 for the nine months ended September 30, 2011
and 2010, respectively. The derivative gains are included in other comprehensive (loss)
income and resulted from prior period impairment charges.
(4)
Average oil prices are calculated by including in total revenue derivative gains
previously recognized into income (loss) and dividing by the total volume for the
period. Previously recognized derivative gains were $2,600 and $6,000 for the three
months ended September 30, 2011 and 2010, respectively. Previously recognized
derivative gains were $8,900 and $16,800 for the nine months ended September 30, 2011
and 2010, respectively. The derivative losses are included in other comprehensive
(loss) income and resulted from prior period impairment charges.
Natural Gas Revenues. Our natural gas revenues were $440,700 and $472,000 for the three
months ended September 30, 2011 and 2010, respectively, a decrease of $31,300 (7%). The $31,300
decrease in natural gas revenues for the three months ended September 30, 2011 as compared to the
prior year similar period was attributable to a $49,800 decrease in our natural gas sales prices
after the effect of financial hedges, which were driven by market conditions, partially offset by a
$18,500 increase in production volumes. Our production volumes increased to 920 mcf per day for the
three months ended September 30, 2011 from 885 mcf per day for the three months ended September 30,
2010, an increase of 35 mcf per day (4%). Production increased due to an increase in pipeline
capacity.
Our natural gas revenues were $1,200,400 and $1,614,600 for the nine months ended September
30, 2011 and 2010, respectively, a decrease of $414,200 (26%). The $414,200 decrease in natural gas
revenues for the nine months ended September 30, 2011 as compared to the prior year similar period
was attributable to a $274,200 decrease in production volumes and a $140,000 decrease in our
natural gas sales prices after the effect of financial hedges, which were driven by market
conditions. Our production volumes decreased to 809 mcf per day for the nine months ended September
30, 2011 from 974 mcf per day for the nine months ended September 30, 2010, a decrease of 165 mcf
per day (17%). The overall decrease in natural gas production volumes for the nine months ended
September 30, 2011 resulted primarily from the normal decline inherent in the life of a well.
Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells
have limited oil production. Our oil revenues were $65,400 and $37,900 for the three months ended
September 30, 2011 and 2010, respectively, an increase of $27,500 (73%). The $27,500 increase in
oil revenues for the three months ended September 30, 2011 as compared to the prior year similar
period was attributable to a $15,600 increase in oil prices after the effect of financial hedges
and an $11,900 increase in production volumes. Our production volumes increased to 9 bbls per day
for the three months ended September 30, 2011 from 7 bbls per day for the three months ended
September 30, 2010, an increase of 2 bbls per day (29%).
Our oil revenues were $185,000 and $145,800 for the nine months ended September 30, 2011 and
2010, respectively, an increase of $39,200 (27%). The $39,200 increase in oil revenues for the nine
months ended September 30, 2011 as compared to the prior year similar period was attributable to a
$41,500 increase in oil prices after the effect of financial hedges, partially offset by a $2,300
decrease in production volumes. Our production volumes decreased to 7.94 bbls per day for the nine
months ended September 30, 2011 from 8.07 bbls per day for the nine months ended September 30,
2010, a decrease of .13 bbl per day (2%).
Costs and Expenses. Production expenses were $231,900 and $248,300 for the three months ended
September 30, 2011 and 2010, respectively, a decrease of $16,400 (7%). Production expenses were
$648,400 and $775,800 for the nine months ended September 30, 2011 and 2010, respectively, a
decrease of $127,400 (16%). These decreases were primarily due to lower transportation fees and
other variable expenses as compared to prior year similar period.
Depletion of oil and gas properties as a percentage of oil and gas revenues were 50% for the
three months ended September 30, 2011 and 2010, respectively; and 48% for the nine months ended
September 30, 2011 and 2010, respectively. These percentage changes are directly attributable to
changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes
in the depletable cost basis of oil and gas properties.
General and administrative expenses for the three months ended September 30, 2011 and 2010
were $41,000 and $36,900, respectively, an increase of $4,100 (11%). For the nine months ended
September 30, 2011 and 2010, these expenses were $124,400 and $120,600, respectively, an increase
of $3,800 (3%). These expenses include third-party costs for services as well as the monthly
administrative fees charged by our MGP. These decreases were primarily due to lower third-party
costs as compared to the prior year similar period.
Liquidity and Capital Resources
Cash provided by operating activities decreased $479,300 in the nine months ended September
30, 2011 to $759,200 as compared to $1,238,500 for the nine months ended September 30, 2010. This
decrease was primarily due to a decrease in net earnings before depletion, net non-cash loss on
hedge instruments and accretion of $429,900 and a decrease in the change in accounts
receivable-affiliate of $79,000 partially offset by an increase in the change in accrued
liabilities of $13,300 and an increase in the change in asset retirement obligation liabilities
settled of $16,300 in the nine months ended September 30, 2011 as compared to the nine months ended
September 30, 2010.
Cash used in investing activities were $7,500 for the nine months ended September 30, 2011 due
to the purchase of tangible equipment. Cash provided by investing activities were $5,500 for the
nine months ended September 30, 2010 from the sale of tangible equipment.
Cash used in financing activities decreased $473,600 during the nine months ended September
30, 2011 to $789,300 from $1,262,900 for the nine months ended September 30, 2010. This decrease
was due to a decrease in cash distributions to partners.
Our MGP may withhold funds for future plugging and abandonment costs. Through September 30,
2011, our MGP had not withheld any funds for this purpose. Any additional funds, if required, will
be obtained from production revenues or borrowings from our MGP or its affiliates, which are not
contractually committed to make loans to us. The amount that we may borrow may not at any time
exceed 5% of our total subscriptions, and we will not borrow from third-parties.
The Partnership is generally limited to the amount of funds generated by the cash flows from
our operations, which we believe is adequate to fund future operations and distributions to our
partners. Historically, there has been no need to borrow funds from our MGP to fund operations.
Subordination by Managing General Partner
Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50%
of its share of net production revenues of the Partnership to provide a distribution to the limited
partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a
cumulative basis, in each of the first five years of Partnership operations, commencing with the
first distribution of net revenues to the limited partners (September 2006). The MGP subordinated
$36,700 and $165,800 of its net production revenue to the limited partners for the nine months
ended September 30, 2011 and 2010, respectively.
The discussion and analysis of our financial condition and results of operations are based
upon our financial statements, which have been prepared in accordance with accounting principles
generally accepted in the United States of America. On an on-going basis, we evaluate our
estimates, including those related to our asset retirement obligations, depletion and certain
accrued receivables and liabilities. We base our estimates on historical experience and on various
other assumptions that we believe reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities that are not readily
apparent from other sources. Actual results may differ from these estimates under different
assumptions or conditions. A discussion of our significant accounting policies we have adopted and
followed in the preparation of our financial statements is included within Notes to Financial
Statements in Part I, Item 1, Financial Statements in this quarterly report and in our Annual
Report on Form 10-K for the year ended December 31, 2010.
ITEM 4.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information
required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed,
summarized and reported within the time periods specified in the SECs rules and forms, and that
such information is accumulated and communicated to our management, including our MGPs Chairman of
the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, as
appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating
the disclosure controls and procedures, our management recognized that any controls and procedures,
no matter how well designed and operated, can provide only reasonable assurance of achieving the
desired control objectives and our management necessarily was required to apply its judgment in
evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision of our MGPs Chairman of the Board of Directors, Chief Executive
Officer, President, and Chief Financial Officer, we have carried out an evaluation of the
effectiveness of our disclosure controls and procedures as of the end of the period covered by this
report. Based upon that evaluation, our MGPs Chairman of the Board of Directors, Chief Executive
Officer, President and Chief Financial Officer, concluded that, at September 30, 2011, our
disclosure controls and procedures were effective at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have been no changes in the Partnerships internal control over financial reporting
during our most recent fiscal quarter that have materially affected, or are reasonably likely to
materially effect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
The Managing General Partner is not aware of any legal proceedings filed against the
Partnership.
Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings
arising in the ordinary course of their collective business. The MGPs management believes that
none of these actions, individually or in the aggregate, will have a material adverse effect on the
MGPs financial condition or results of operations.
Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Atlas America Series 26-2005 L.P.
ATLAS RESOURCES, LLC, Managing General Partner
Date: November 10, 2011
By:
/s/ FREDDIE M. KOTEK
Freddie M. Kotek, Chairman of the
Board of Directors, Chief Executive Officer and President
In accordance with the Exchange Act, this report has been signed by the following person on
behalf of the registrant and in the capacities and on the dates indicated.
I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 2011
of Atlas America Series 26-2005 L.P.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this
report;
4.
The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have;
a)
designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant is made known to us by others within the entity,
particularly during the period in which this report is being prepared;
b)
designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally
accepted accounting principles;
c)
evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and
d)
disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and
5.
The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the
audit committee of the registrants board of directors (or persons performing the equivalent
functions):
a)
all significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and
b)
any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting.
By:
Name:
/s/ FREDDIE M. KOTEK
Freddie M. Kotek
Title:
Chief Executive Officer of the Managing General Partner
I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 2011
of Atlas America Series 26-2005 L.P.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this
report;
5.
The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have;
a)
designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant is made known to us by others within the entity,
particularly during the period in which this report is being prepared;
b)
designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally
accepted accounting principles;
c)
evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and
d)
disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and
5.
The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the
audit committee of the registrants board of directors (or persons performing the equivalent
functions):
a)
all significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and
b)
any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting.
By:
Name:
/s/ SEAN P. MCGRATH
Sean P. McGrath
Title:
Chief Financial Officer of the Managing General Partner
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Atlas America Series 26-2005 L.P. (the
Partnership) on Form 10-Q for the period ended September 30, 2011 as filed with the Securities
and Exchange Commission on the date hereof (the Report), I, Freddie M. Kotek, Chief Executive
Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)
the Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, and
(2)
the information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
By:
Name:
/s/ FREDDIE M. KOTEK
Freddie M. Kotek
Title:
Chief Executive Officer of the Managing General Partner
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Atlas America Series 26-2005 L.P. (the
Partnership) on Form 10-Q for the period ended September 30, 2011 as filed with the Securities
and Exchange Commission on the date hereof (the Report), I, Matthew A. Jones, Chief Financial
Officer of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1)
the Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, and
(2)
the information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Partnership.
By:
Name:
/s/ SEAN P. MCGRATH
Sean P. McGrath
Title:
Chief Financial Officer of the Managing General Partner
Date:
November 10, 2011
EX-101.INS
6
cik0001342514-20110930.xml
EX-101 INSTANCE DOCUMENT
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<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 3 — ASSET RETIREMENT OBLIGATION</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The estimated liability is based on the MGP's historical experience 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 liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">A reconciliation of the Partnership's liability for plugging and abandonment costs for the periods indicated is as follows: </div>
<div align="center">
<table style="font-size: 10pt;" border="0" cellspacing="0" cellpadding="0" width="100%">
<tr valign="bottom"><td width="44%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td colspan="6" nowrap="nowrap" align="center"><b>Three Months Ended</b></td>
<td> </td>
<td> </td>
<td colspan="6" nowrap="nowrap" align="center"><b>Nine Months Ended</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Asset retirement obligation at beginning of period</div></td>
<td> </td>
<td align="left">$</td>
<td align="right">1,936,600</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">1,526,200</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">1,880,200</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">1,497,600</td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Liabilities settled</div></td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(16,300</td>
<td nowrap="nowrap">)</td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Accretion expense</div></td>
<td> </td>
<td> </td>
<td align="right">28,200</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">22,600</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">84,600</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">67,500</td>
<td> </td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Asset retirement obligation at end of period</div></td>
<td> </td>
<td align="left">$</td>
<td align="right">1,964,800</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">1,548,800</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">1,964,800</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">1,548,800</td>
<td> </td></tr></table></div></div>-16300112711001012610094780067570014840012950010550067900-18900-37600<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 5 — COMPREHENSIVE (LOSS) INCOME</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Comprehensive (loss) income includes net (loss) income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net (loss) income. These changes, other than net (loss) income, are referred to as "other comprehensive (loss) income" and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges, and changes in the estimated amount of future monetized proceeds to be received (See Note 4). </div></div>
<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify">The monetized proceeds included in accounts receivable affiliate have been allocated to the Partnership based on estimated future production in relation to all other partnerships' future production eligible to receive monetized hedge proceeds. As actual production is realized, there may be a corresponding difference in the Partnership's actual share of monetized hedge proceeds received than what was previously estimated. This component is shown as "Difference in estimated monetized gains receivable." The following table sets forth the calculation of the Partnership's comprehensive (loss) income: </div>
<div align="center">
<table style="font-size: 10pt;" border="0" cellspacing="0" cellpadding="0" width="100%">
<tr valign="bottom"><td width="44%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td colspan="6" nowrap="nowrap" align="center"><b>Three Months Ended</b></td>
<td> </td>
<td> </td>
<td colspan="6" nowrap="nowrap" align="center"><b>Nine Months Ended</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Net (loss) income</div></td>
<td> </td>
<td nowrap="nowrap" align="left">$</td>
<td align="right">(49,800</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td nowrap="nowrap" align="left">$</td>
<td align="right">(54,100</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td nowrap="nowrap" align="left">$</td>
<td align="right">(135,400</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td nowrap="nowrap" align="left">$</td>
<td align="right">(42,400</td>
<td nowrap="nowrap">)</td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Other comprehensive (loss) income:</div></td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 30px;">Unrealized holding (loss) gain on hedging contracts</div></td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">403,400</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">17,700</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">962,600</td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 30px;">MGP portion of non-cash loss on hedge instruments</div></td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">106,000</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 30px;">Difference in estimated monetized gains receivable</div></td>
<td> </td>
<td> </td>
<td align="right">5,000</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">18,800</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">—</td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 30px;">Less: reclassification adjustment for (gains) losses realized in net earnings (loss)</div></td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(53,300</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(83,000</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(261,000</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(246,900</td>
<td nowrap="nowrap">)</td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Total other comprehensive (loss) income</div></td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(48,300</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td> </td>
<td align="right">320,400</td>
<td> </td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(118,500</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td> </td>
<td align="right">715,700</td>
<td> </td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Comprehensive (loss) income</div></td>
<td> </td>
<td nowrap="nowrap" align="left">$</td>
<td align="right">(98,100</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td align="left">$</td>
<td align="right">266,300</td>
<td> </td>
<td> </td>
<td nowrap="nowrap" align="left">$</td>
<td align="right">(253,900</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td align="left">$</td>
<td align="right">673,300</td>
<td> </td></tr></table></div></div>838900256200663400132500530900254800<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 4 — DERIVATIVE INSTRUMENTS</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The MGP, on behalf of the Partnership, historically used a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP entered into financial instruments to hedge the Partnership's forecasted natural gas and crude oil against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap agreements, the Partnership received or paid a fixed price and received or remitted a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Historically, the MGP has entered into natural gas and crude oil future option contracts and collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil prices. At any point in time, such contracts included 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. Crude oil contracts are based on a West Texas Intermediate ("WTI") index. These contracts qualified and were designated as cash flow hedges and recorded at their fair values. </div></div>
<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The MGP formally documented all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This included matching the commodity derivative contracts to the forecasted transactions. The MGP assessed, both at the inception of the derivative and on an ongoing basis, whether the derivative was effective in offsetting changes in the forecasted cash flow of the hedged item. If it determined that a derivative was not effective as a hedge or that it had ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP discontinued hedge accounting for the derivative and subsequent changes in the derivative fair value, which was determined by the MGP through the utilization of market data, were recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership's statements of operations. For derivatives qualifying as hedges, the Partnership recognized the effective portion of changes in fair value in partners' capital as accumulated other comprehensive income and reclassified the portion relating to commodity derivatives to gas and oil production revenues for the Partnership's derivatives within the Partnership's statements of operations as the underlying transactions were settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognized changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occurred. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. At September 30, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $239,000 in accounts receivable-affiliate and $182,000 in long-term receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership's balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments' term. As a result of the monetization and the early settlement of natural gas and oil derivative instruments and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheets in other comprehensive income of $307,600 as of September 30, 2011. Unrealized gains, net of the MGP's interest, previously recognized into income as a result of prior period impairments included in accumulated other comprehensive income were $113,400. The MGP's portion of the unrealized gains was written-off as part of the terms related to the acquisition of the Transferred Business. For the three and nine months ended September 30, 2011, the Partnership reclassified $106,000 of unrealized gains previously recognized into income from prior period impairments related to the MGP from a hedge receivable due from affiliate to a non-cash distribution to the MGP. As such, $106,000 was recorded as a distribution to partners on the statement of changes in partners' capital. During the nine months ended September 30, 2011, $176,900 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $307,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $158,000 of net gains to the Partnership's statements of operations over the next twelve month period and the remaining $149,600 in later periods. </div></div>
<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The following tables summarize the fair value of the Partnership's derivative instruments as of December 31, 2010, as well as the gain or loss recognized in the statements of operations for the three and nine months ended September 30, 2011 and 2010: </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Fair Value of Derivative Instruments:</b> </div>
<div align="center">
<table style="font-size: 10pt;" border="0" cellspacing="0" cellpadding="0" width="100%">
<tr valign="bottom"><td width="52%"> </td>
<td width="3%"> </td>
<td width="31%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center">Fair Value</td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td nowrap="nowrap" align="center">Balance Sheet</td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center">December 31,</td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td style="border-bottom: #000000 1px solid;" nowrap="nowrap" align="left">Derivatives in Cash Flow Hedging Relationships</td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" nowrap="nowrap" align="center">Location</td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center">2010</td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Commodity Contracts</div></td>
<td> </td>
<td valign="top" align="left">Current assets</td>
<td> </td>
<td align="left">$</td>
<td align="right">407,600</td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left">Long-term assets</td>
<td> </td>
<td> </td>
<td align="right">399,000</td>
<td> </td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td align="right">806,600</td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left">Current liabilities</td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(7,700</td>
<td nowrap="nowrap">)</td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left">Long-term liabilities</td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(74,700</td>
<td nowrap="nowrap">)</td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(82,400</td>
<td nowrap="nowrap">)</td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left">Total</td>
<td> </td>
<td align="left">$</td>
<td align="right">724,200</td>
<td> </td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td style="border-top: #000000 3px double;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr></table></div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Effects of Derivative Instruments on Statement of Operations:</b> </div>
<div align="center">
<table style="font-size: 10pt;" border="0" cellspacing="0" cellpadding="0" width="100%">
<tr valign="bottom"><td width="20%"> </td>
<td width="3%"> </td>
<td width="21%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>Three Months Ended</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>Nine Months Ended</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Derivative in Cash Flow</div></td>
<td> </td>
<td valign="top" align="left">Gain Recognized in</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Hedging Relationships</div></td>
<td> </td>
<td valign="top" align="left">OCI on Derivatives</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left">Commodity Contracts</td>
<td> </td>
<td align="left">$</td>
<td align="right">—</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">403,400</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">17,700</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">962,600</td>
<td> </td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td style="border-top: #000000 3px double;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 3px double;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 3px double;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 3px double;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr></table></div>
<div align="center">
<table style="font-size: 10pt;" border="0" cellspacing="0" cellpadding="0" width="100%">
<tr valign="bottom"><td width="20%"> </td>
<td width="3%"> </td>
<td width="21%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>Three Months Ended</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="6" nowrap="nowrap" align="center"><b>Nine Months Ended</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Location of Gain</div></td>
<td> </td>
<td valign="top" align="left">Gain Reclassified from</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Reclassified from</div></td>
<td> </td>
<td valign="top" align="left">OCI into Net Loss (Income)</td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Accumulated</div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">OCI into (Loss) Income</div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left"> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td valign="top" align="left">Gas and Oil Revenue</td>
<td> </td>
<td align="left">$</td>
<td align="right">53,300</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">83,000</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">261,000</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">246,900</td></tr></table></div></div>1262900789300434700607800182000<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 6 — FAIR VALUE OF FINANCIAL INSTRUMENTS</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value: </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify"><i>Level 1— </i>Quoted prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify"><i>Level 2— </i>Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify"><i>Level 3— </i>Unobservable inputs that reflect the entities own assumptions about the assumptions that market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques. </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Assets and Liabilities Measured at Fair Value on a Recurring Basis</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership used a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership's commodity derivative contracts were valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 3). </div></div>1206003690012440044900795004100010600028540002526100-144900-65900-113002000112711001012610021200155006014900531210014001400737000202300534700-1262900-7893005500-75001238500759200-42400-54100-135400-5700-129700-4980012330022800-5700-5400-165700-76900-129700-44400-118-55-93-32775800248300648400231900992430092684001760400509900138540050610018028005640001520800555900<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 1 <font style="font-family: Symbol;" class="_mt">-</font> DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Atlas America Series 26-2005 L.P. (the "Partnership") is a Delaware limited partnership and formed on May 26, 2005 with Atlas Resources, LLC serving as its Managing General Partner and operator ("Atlas Resources" or "MGP"). Atlas Resources is an indirect subsidiary of Atlas Energy, L.P., formerly Atlas Pipeline Holdings, L.P. ("Atlas Energy") (NYSE: ATLS). On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. ("APL") (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business; its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the "Transferred Business"). </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Atlas Energy recently announced that it intends to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. ("Atlas Resource Partners"), which will hold substantially all of ATLS' current natural gas and oil development and production assets and the partnership management business. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Atlas Resources' focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Indiana and/or Colorado basin regions of the United States of America. Atlas Resources is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Resources with the personnel necessary to manage its assets and raise capital. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2010 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America ("U.S. GAAP") for interim reporting. They do not include all disclosures normally made in financial statements contained in the Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2010. The results of operations for the three and nine months ended September 30, 2011 may not necessarily be indicative of the results of operations for the year ended December 31, 2011. </div></div>-118500-118500-257200-7870092950004261002854000601490081458003076002526100531210089530028550060980075005500<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 7 <font style="font-family: Symbol;" class="_mt">-</font> TRANSACTIONS WITH ATLAS RESOURCES, LLC, AND ITS AFFILIATES</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement: </div>
<div style="margin-top: 10pt;">
<table style="font-size: 10pt;" border="0" cellspacing="0" cellpadding="0" width="100%">
<tr style="background: none transparent scroll repeat 0% 0%; color: #000000; font-size: 10pt;" valign="top"><td style="background: none transparent scroll repeat 0% 0%;" width="4%"> </td>
<td width="3%" nowrap="nowrap" align="left"><b>•</b></td>
<td width="1%"> </td>
<td>
<div style="text-align: justify;">Administrative costs which are included in general and administrative expenses in the Partnership's statements of operations are payable at $75 per well per month. Administrative costs incurred for the three and nine months ended September 30, 2011 were $26,400 and $78,300, respectively. Administrative costs incurred for the three and nine months ended September 30, 2010 were $27,500 and $81,900, respectively.</div></td></tr>
<tr><td style="font-size: 8pt;"> </td></tr>
<tr style="background: none transparent scroll repeat 0% 0%; color: #000000; font-size: 10pt;" valign="top"><td style="background: none transparent scroll repeat 0% 0%;" width="4%"> </td>
<td width="3%" nowrap="nowrap" align="left"><b>•</b></td>
<td width="1%"> </td>
<td>
<div style="text-align: justify;">Monthly well supervision fees which are included in production expenses in the Partnership's statements of operations are payable at $318 per well per month in 2011 and 2010, for operating and maintaining the wells. Well supervision fees incurred for the three and nine months ended September 30, 2011 were $110,700 and $327,500, respectively. Well supervision fees incurred for the three and nine months ended September 30, 2010 were $115,000 and $342,300, respectively.</div></td></tr>
<tr><td style="font-size: 8pt;"> </td></tr>
<tr style="background: none transparent scroll repeat 0% 0%; color: #000000; font-size: 10pt;" valign="top"><td style="background: none transparent scroll repeat 0% 0%;" width="4%"> </td>
<td width="3%" nowrap="nowrap" align="left"><b>•</b></td>
<td width="1%"> </td>
<td>
<div style="text-align: justify;">Transportation fees which are included in production expenses in the Partnership's statements of operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three and nine months ended September 30, 2011 were $58,700 and $156,400, respectively. Transportation fees incurred for the three and nine months ended September 30, 2010 were $66,100 and $223,600, respectively.</div></td></tr></table></div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the Partnership's Balance Sheets represents the net production revenues due from the MGP. </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Subordination by Managing General Partner</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to provide a distribution to the limited partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of net revenues to the limited partners (September 2006). The MGP subordinated $36,700 and $165,800 of its net production revenue to the limited partners for the nine months ended September 30, 2011 and 2010, respectively. </div></div>17604005099001385400506100<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">In management's opinion, all adjustments necessary for a fair presentation of the Partnership's financial position, results of operations and cash flows for the periods disclosed have been made. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">In addition to matters discussed further in this note, the Partnership's significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership's annual report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission ("SEC"). </div></div>
<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Use of Estimates</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Preparation of 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 that exist at the date of the Partnership's financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership's financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months' financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months' financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2011 and 2010 represent actual results in all material respects (see "Revenue Recognition" accounting policy for further description). </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Accounts Receivable and Allowance for Possible Losses</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership's customers and adjusts credit limits based upon payment history and the customer's current creditworthiness, as determined by review of the Partnership's customers' credit information. Credit is extended on an unsecured basis to many of its energy customers. As of September 30, 2011 and December 31, 2010, the MGP's credit evaluation indicated that the Partnership had no need for an allowance for possible losses. </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Oil and Gas Properties</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis ("Mcfe") at the rate of one barrel equals six Mcf. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership's depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership's statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets. </div></div>
<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div align="center">
<table style="font-size: 10pt;" border="0" cellspacing="0" cellpadding="0" width="100%">
<tr valign="bottom"><td width="72%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td>
<td width="3%"> </td>
<td width="1%"> </td>
<td width="9%"> </td>
<td width="1%"> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>September 30,</b></td>
<td> </td>
<td> </td>
<td colspan="2" nowrap="nowrap" align="center"><b>December 31,</b></td>
<td> </td></tr>
<tr style="font-size: 10pt;" valign="bottom"><td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2011</b></td>
<td> </td>
<td> </td>
<td style="border-bottom: #000000 1px solid;" colspan="2" nowrap="nowrap" align="center"><b>2010</b></td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Proved properties:</div></td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Leasehold interests</div></td>
<td> </td>
<td align="left">$</td>
<td align="right">1,110,900</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">1,110,900</td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Wells and related equipment</div></td>
<td> </td>
<td> </td>
<td align="right">44,068,700</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">44,061,200</td>
<td> </td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td> </td>
<td align="right">45,179,600</td>
<td> </td>
<td> </td>
<td> </td>
<td align="right">45,172,100</td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td>
<td> </td></tr>
<tr style="background: #cceeff;" valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Accumulated depletion</div></td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(35,911,200</td>
<td nowrap="nowrap">)</td>
<td> </td>
<td nowrap="nowrap" align="left"> </td>
<td align="right">(35,247,800</td>
<td nowrap="nowrap">)</td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 1px solid;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr>
<tr valign="bottom"><td>
<div style="text-indent: -15px; margin-left: 15px;">Oil and gas properties</div></td>
<td> </td>
<td align="left">$</td>
<td align="right">9,268,400</td>
<td> </td>
<td> </td>
<td align="left">$</td>
<td align="right">9,924,300</td>
<td> </td></tr>
<tr style="font-size: 1px;"><td>
<div style="text-indent: -15px; margin-left: 15px;"> </div></td>
<td> </td>
<td style="border-top: #000000 3px double;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td>
<td> </td>
<td style="border-top: #000000 3px double;" colspan="2" nowrap="nowrap" align="right"> </td>
<td> </td></tr></table></div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Impairment of Long-Lived Assets</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The review of the Partnership's oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties, less the applicable accumulated depletion, 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 current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future 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. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. There was no impairment charges recognized during the three and nine months ended September 30, 2011 or for the year ended December 31, 2010. </div></div>
<div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Working Interest</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions ("working interest"). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Revenue Recognition</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership's percentage ownership of working interest. Generally, the Partnership's sales contracts are based on pricing provisions that are tied to a market index with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership's records and management estimates of the related commodity sales and transportation fees which are, in turn, based upon applicable product prices (see "Use of Estimates" accounting policy for further description). The Partnership had unbilled revenues at September 30, 2011 and December 31, 2010 of $256,200 and $291,400, respectively, which are included in accounts receivable — affiliate within the Partnership's balance sheets. </div>
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>Recently Issued Accounting Standards</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">In June 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update 2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in partners' capital. These changes apply to both annual and interim financial statements. Update 2011-05 will be effective for public entities' fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership will apply the requirements of Update 2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. </div></div><div style="width: 7.5in; font-family: 'Times New Roman',Times,serif; margin-left: 0.25in;">
<div style="margin-top: 10pt; font-size: 10pt;" align="justify"><b>NOTE 8 — SUBSEQUENT EVENTS</b> </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify">Management has considered for disclosure any material subsequent events through the date the financial statements were issued. </div>
<div style="margin-top: 10pt; text-indent: 32px; font-size: 10pt;" align="justify"><i>Formation of Atlas Resource Partners, L.P</i>. On October 17, 2011, Atlas Energy announced that its board of directors has approved a plan to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. ("Atlas Resource Partners"), which will hold substantially all of Atlas Energy's current natural gas and oil development, and production assets and the partnership management business, including the MGP. Upon consummation of the transaction, Atlas Energy will retain a 78.4% limited partner interest in Atlas Resource Partners and intends to distribute a 19.6% limited partner interest in Atlas Resource Partners to Atlas Energy unit holders. Atlas Energy will also own the newly created general partner of Atlas Resource Partners, which will own a 2% general partner interest and all of the incentive distribution rights in the newly formed partnership. Completion of the transaction is subject to a number of conditions, including final approval by the Atlas Energy's board of directors, as well as the effectiveness of a Form 10 registration statement that Atlas Resource Partners filed with the SEC on October 17, 2011. The transaction is expected to close in the first quarter of 2012. The MGP anticipates that this transaction will have no impact on the Partnership's operations. </div></div>EX-101.SCH
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Amount of accretion expense recognized during the period that is associated with an asset retirement obligation. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.
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The aggregate total of expenses of managing and administering the affairs of an entity, including affiliates of the reporting entity, which are not directly or indirectly associated with the manufacture, sale or creation of a product or product line.
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Costs incurred to operate and maintain an entities' wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.
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Generally recurring costs associated with normal operations except for the portion of these expenses which can be clearly related to production and included in cost of sales or services. Excludes Selling, General and Administrative Expense.
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This is focus fiscal period of the document report. For a first quarter 2006 quarterly report, which may also provide financial information from prior periods, the first fiscal quarter should be given as the fiscal period focus. Values: FY, Q1, Q2, Q3, Q4, H1, H2, M9, T1, T2, T3, M8, CY.
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The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1— Quoted prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2— Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3— Unobservable inputs that reflect the entities own assumptions about the assumptions that market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership used a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership's commodity derivative contracts were valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 3).
The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.
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NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In management's opinion, all adjustments necessary for a fair presentation of the Partnership's financial position, results of operations and cash flows for the periods disclosed have been made.
In addition to matters discussed further in this note, the Partnership's significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership's annual report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission ("SEC").
Use of Estimates
Preparation of 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 that exist at the date of the Partnership's financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership's financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months' financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months' financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2011 and 2010 represent actual results in all material respects (see "Revenue Recognition" accounting policy for further description).
Accounts Receivable and Allowance for Possible Losses
In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership's customers and adjusts credit limits based upon payment history and the customer's current creditworthiness, as determined by review of the Partnership's customers' credit information. Credit is extended on an unsecured basis to many of its energy customers. As of September 30, 2011 and December 31, 2010, the MGP's credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
Oil and Gas Properties
Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis ("Mcfe") at the rate of one barrel equals six Mcf.
The Partnership's depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership's statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.
September 30,
December 31,
2011
2010
Proved properties:
Leasehold interests
$
1,110,900
$
1,110,900
Wells and related equipment
44,068,700
44,061,200
45,179,600
45,172,100
Accumulated depletion
(35,911,200
)
(35,247,800
)
Oil and gas properties
$
9,268,400
$
9,924,300
Impairment of Long-Lived Assets
The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Partnership's oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties, less the applicable accumulated depletion, 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 current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future 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.
The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. There was no impairment charges recognized during the three and nine months ended September 30, 2011 or for the year ended December 31, 2010.
Working Interest
The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions ("working interest"). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
Revenue Recognition
The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership's percentage ownership of working interest. Generally, the Partnership's sales contracts are based on pricing provisions that are tied to a market index with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.
The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership's records and management estimates of the related commodity sales and transportation fees which are, in turn, based upon applicable product prices (see "Use of Estimates" accounting policy for further description). The Partnership had unbilled revenues at September 30, 2011 and December 31, 2010 of $256,200 and $291,400, respectively, which are included in accounts receivable — affiliate within the Partnership's balance sheets.
Recently Issued Accounting Standards
In June 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update 2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in partners' capital. These changes apply to both annual and interim financial statements. Update 2011-05 will be effective for public entities' fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership will apply the requirements of Update 2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
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Management has considered for disclosure any material subsequent events through the date the financial statements were issued.
Formation of Atlas Resource Partners, L.P. On October 17, 2011, Atlas Energy announced that its board of directors has approved a plan to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. ("Atlas Resource Partners"), which will hold substantially all of Atlas Energy's current natural gas and oil development, and production assets and the partnership management business, including the MGP. Upon consummation of the transaction, Atlas Energy will retain a 78.4% limited partner interest in Atlas Resource Partners and intends to distribute a 19.6% limited partner interest in Atlas Resource Partners to Atlas Energy unit holders. Atlas Energy will also own the newly created general partner of Atlas Resource Partners, which will own a 2% general partner interest and all of the incentive distribution rights in the newly formed partnership. Completion of the transaction is subject to a number of conditions, including final approval by the Atlas Energy's board of directors, as well as the effectiveness of a Form 10 registration statement that Atlas Resource Partners filed with the SEC on October 17, 2011. The transaction is expected to close in the first quarter of 2012. The MGP anticipates that this transaction will have no impact on the Partnership's operations.
The entire disclosure for significant events or transactions that occurred after the balance sheet date through the date the financial statements were issued or the date the financial statements were available to be issued. Examples include: the sale of a capital stock issue, purchase of a business, settlement of litigation, catastrophic loss, significant foreign exchange rate changes, loans to insiders or affiliates, and transactions not in the ordinary course of business.
NOTE 7 - TRANSACTIONS WITH ATLAS RESOURCES, LLC, AND ITS AFFILIATES
The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement:
Administrative costs which are included in general and administrative expenses in the Partnership's statements of operations are payable at $75 per well per month. Administrative costs incurred for the three and nine months ended September 30, 2011 were $26,400 and $78,300, respectively. Administrative costs incurred for the three and nine months ended September 30, 2010 were $27,500 and $81,900, respectively.
Monthly well supervision fees which are included in production expenses in the Partnership's statements of operations are payable at $318 per well per month in 2011 and 2010, for operating and maintaining the wells. Well supervision fees incurred for the three and nine months ended September 30, 2011 were $110,700 and $327,500, respectively. Well supervision fees incurred for the three and nine months ended September 30, 2010 were $115,000 and $342,300, respectively.
Transportation fees which are included in production expenses in the Partnership's statements of operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three and nine months ended September 30, 2011 were $58,700 and $156,400, respectively. Transportation fees incurred for the three and nine months ended September 30, 2010 were $66,100 and $223,600, respectively.
The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the Partnership's Balance Sheets represents the net production revenues due from the MGP.
Subordination by Managing General Partner
Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to provide a distribution to the limited partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of net revenues to the limited partners (September 2006). The MGP subordinated $36,700 and $165,800 of its net production revenue to the limited partners for the nine months ended September 30, 2011 and 2010, respectively.
The entire disclosure for related party transactions, including the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 1-4
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Amount of accretion expense recognized during the period that is associated with an asset retirement obligation. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.
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-Number 143
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-Number 143
-Paragraph 22
-Subparagraph c(3)
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Amount of asset retirement obligations settled, or otherwise disposed of, during the period. This may include asset retirement obligations transferred to third parties associated with the sale of a long-lived asset.
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-Subparagraph c(2)
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Includes currency on hand as well as demand deposits with banks or financial institutions. It also includes other kinds of accounts that have the general characteristics of demand deposits in that the Entity may deposit additional funds at any time and also effectively may withdraw funds at any time without prior notice or penalty. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present minimal risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased three years ago does not become a cash equivalent when its remaining maturity is three months. Compensating balance arrangements that do not legally restrict the withdrawal or usage of cash amounts may be reported as Cash and Cash Equivalents, while legally restricted deposits held as compensating balances against borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular deposits are not generally reported as cash and cash equivalents. Includes cash and cash equivalents associated with the entity's continuing operations. Excludes cash and cash equivalents associated with the disposal group (and discontinued operation).
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-Number 95
-Paragraph 7
-Footnote 1
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The increase (decrease) during the reporting period in cash and cash equivalents. While for technical reasons this element has no balance attribute, the default assumption is a debit balance consistent with its label.
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The increase (decrease) during the reporting period in receivables to be collected from an entity that is controlling, under the control of, or within the same control group as the reporting entity by means of direct or indirect ownership.
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
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-Number 95
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The net cash from (used in) all of the entity's operating activities, including those of discontinued operations, of the reporting entity. Operating activities generally involve producing and delivering goods and providing services. Operating activity cash flows include transactions, adjustments, and changes in value that are not defined as investing or financing activities. While for technical reasons this element has no balance attribute, the default assumption is a debit balance consistent with its label.
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-Number 95
-Paragraph 26
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-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 10, 15
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-Number 95
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-Subparagraph c
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-Number 95
-Paragraph 16
-Subparagraph c
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The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.
The estimated liability is based on the MGP's historical experience 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 liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.
A reconciliation of the Partnership's liability for plugging and abandonment costs for the periods indicated is as follows:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2011
2010
2011
2010
Asset retirement obligation at beginning of period
The entire disclosure for an asset retirement obligation and the associated long-lived asset. An asset retirement obligation is a legal obligation associated with the disposal or retirement from service of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.
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The MGP, on behalf of the Partnership, historically used a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP entered into financial instruments to hedge the Partnership's forecasted natural gas and crude oil against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap agreements, the Partnership received or paid a fixed price and received or remitted a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.
Historically, the MGP has entered into natural gas and crude oil future option contracts and collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil prices. At any point in time, such contracts included 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. Crude oil contracts are based on a West Texas Intermediate ("WTI") index. These contracts qualified and were designated as cash flow hedges and recorded at their fair values.
The MGP formally documented all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This included matching the commodity derivative contracts to the forecasted transactions. The MGP assessed, both at the inception of the derivative and on an ongoing basis, whether the derivative was effective in offsetting changes in the forecasted cash flow of the hedged item. If it determined that a derivative was not effective as a hedge or that it had ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP discontinued hedge accounting for the derivative and subsequent changes in the derivative fair value, which was determined by the MGP through the utilization of market data, were recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership's statements of operations. For derivatives qualifying as hedges, the Partnership recognized the effective portion of changes in fair value in partners' capital as accumulated other comprehensive income and reclassified the portion relating to commodity derivatives to gas and oil production revenues for the Partnership's derivatives within the Partnership's statements of operations as the underlying transactions were settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognized changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occurred.
Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. At September 30, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $239,000 in accounts receivable-affiliate and $182,000 in long-term receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership's balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments' term. As a result of the monetization and the early settlement of natural gas and oil derivative instruments and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheets in other comprehensive income of $307,600 as of September 30, 2011. Unrealized gains, net of the MGP's interest, previously recognized into income as a result of prior period impairments included in accumulated other comprehensive income were $113,400. The MGP's portion of the unrealized gains was written-off as part of the terms related to the acquisition of the Transferred Business. For the three and nine months ended September 30, 2011, the Partnership reclassified $106,000 of unrealized gains previously recognized into income from prior period impairments related to the MGP from a hedge receivable due from affiliate to a non-cash distribution to the MGP. As such, $106,000 was recorded as a distribution to partners on the statement of changes in partners' capital. During the nine months ended September 30, 2011, $176,900 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $307,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $158,000 of net gains to the Partnership's statements of operations over the next twelve month period and the remaining $149,600 in later periods.
The following tables summarize the fair value of the Partnership's derivative instruments as of December 31, 2010, as well as the gain or loss recognized in the statements of operations for the three and nine months ended September 30, 2011 and 2010:
Fair Value of Derivative Instruments:
Fair Value
Balance Sheet
December 31,
Derivatives in Cash Flow Hedging Relationships
Location
2010
Commodity Contracts
Current assets
$
407,600
Long-term assets
399,000
806,600
Current liabilities
(7,700
)
Long-term liabilities
(74,700
)
(82,400
)
Total
$
724,200
Effects of Derivative Instruments on Statement of Operations:
The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
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-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
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Comprehensive (loss) income includes net (loss) income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net (loss) income. These changes, other than net (loss) income, are referred to as "other comprehensive (loss) income" and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges, and changes in the estimated amount of future monetized proceeds to be received (See Note 4).
The monetized proceeds included in accounts receivable affiliate have been allocated to the Partnership based on estimated future production in relation to all other partnerships' future production eligible to receive monetized hedge proceeds. As actual production is realized, there may be a corresponding difference in the Partnership's actual share of monetized hedge proceeds received than what was previously estimated. This component is shown as "Difference in estimated monetized gains receivable." The following table sets forth the calculation of the Partnership's comprehensive (loss) income:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2011
2010
2011
2010
Net (loss) income
$
(49,800
)
$
(54,100
)
$
(135,400
)
$
(42,400
)
Other comprehensive (loss) income:
Unrealized holding (loss) gain on hedging contracts
—
403,400
17,700
962,600
MGP portion of non-cash loss on hedge instruments
—
—
106,000
—
Difference in estimated monetized gains receivable
5,000
—
18,800
—
Less: reclassification adjustment for (gains) losses realized in net earnings (loss)
The entire disclosure for comprehensive income. Includes, but is not limited to, the following: 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income. Components of comprehensive income include: (1) foreign currency translation adjustments; (2) gains (losses) on foreign currency transactions that are designated as, and are effective as, economic hedges of a net investment in a foreign entity; (3) gains (losses) on intercompany foreign currency transactions that are of a long-term-investment nature, when the entities to the transaction are consolidated, combined, or accounted for by the equity method in the reporting enterprise's financial statements; (4) change in the market value of a futures contract that qualifies as a hedge of an asset reported at fair value; (5) unrealized holding gains (losses) on available-for-sale securities and that resulting from transfers of debt securities from the held-to-maturity category to the available-for-sale category; (6) a net loss recognized as an additional pension liability not yet recognized as net periodic pension cost; and (7) the net gain (loss) and net prior service cost or credit for pension plans and other postretirement benefit plans.
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14-26
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Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to provide a distribution to the limited partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of net revenues to the limited partners.
Amount of accretion expense recognized during the period that is associated with an asset retirement obligation. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.
-Name Statement of Financial Accounting Standard (FAS)
-Number 143
-Paragraph 13, 14
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-Name Statement of Financial Accounting Standard (FAS)
-Number 143
-Paragraph 22
-Subparagraph c(3)
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-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28
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The aggregate total of expenses of managing and administering the affairs of an entity, including affiliates of the reporting entity, which are not directly or indirectly associated with the manufacture, sale or creation of a product or product line.
Revenue from natural gas production during the reporting period. Natural gas consists largely of the hydrocarbon methane, and is found in underground formations either by itself or with crude oil.
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-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 10, 15
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-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28, 29, 30
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Pre tax change in accumulated gains and losses from derivative instruments designated and qualifying as the effective portion of cash flow hedges, net of reclassifications into earnings during the period. A cash flow hedge is a hedge of the exposure to variability in the cash flows of a recognized asset or liability or a forecasted transaction that is attributable to a particular risk. Includes an entity's share of an equity investee's increase or decrease in deferred hedging gains or losses. While for technical reasons this element has no balance attribute, the default assumption is a credit balance consistent with its label.
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 46
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-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 24
-Subparagraph b
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-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-Subparagraph b(1)
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-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 31, 46
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-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14, 17, 20, 26
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-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14, 17, 20, 24, 26
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NOTE 1 - DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Atlas America Series 26-2005 L.P. (the "Partnership") is a Delaware limited partnership and formed on May 26, 2005 with Atlas Resources, LLC serving as its Managing General Partner and operator ("Atlas Resources" or "MGP"). Atlas Resources is an indirect subsidiary of Atlas Energy, L.P., formerly Atlas Pipeline Holdings, L.P. ("Atlas Energy") (NYSE: ATLS). On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. ("APL") (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business; its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the "Transferred Business").
Atlas Energy recently announced that it intends to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. ("Atlas Resource Partners"), which will hold substantially all of ATLS' current natural gas and oil development and production assets and the partnership management business.
Atlas Resources' focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Indiana and/or Colorado basin regions of the United States of America. Atlas Resources is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Resources with the personnel necessary to manage its assets and raise capital.
The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2010 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America ("U.S. GAAP") for interim reporting. They do not include all disclosures normally made in financial statements contained in the Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2010. The results of operations for the three and nine months ended September 30, 2011 may not necessarily be indicative of the results of operations for the year ended December 31, 2011.
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Payable to general partner for the commodity derivatives that were internally allocated to the drilling partnership. The liability is based upon the fair values of the internally allocated derivative contracts to the drilling partnership as of the balance sheet date. These derivative contracts meet the criteria of being accounted for as derivative instruments (hedges) and which are expected to be converted into cash or otherwise disposed after a year or beyond the normal operating cycle, if longer, net of the effects of the master netting arrangements.
Receivable from general partner for the commodity derivatives that were internally allocated to the drilling partnership. The receivables are based upon the fair values of the internally allocated derivative contracts to the drilling partnership as of the balance sheet date. These derivative contracts meet the criteria of being accounted for as derivative instruments (hedges) and which are expected to be converted into cash or otherwise disposed after a year or beyond the normal operating cycle, if longer, net of the effects of the master netting arrangements.
Payable to general partner for the commodity derivatives that were internally allocated to the drilling partnership. The liability is based upon the fair values of the internally allocated derivative contracts to the drilling partnership as of the balance sheet date. These derivative contracts meet the criteria of being accounted for as derivative instruments (hedges) and which are expected to be converted into cash or otherwise disposed of within a year or the normal operating cycle, if longer, net of the effects of the master netting arrangements.
Receivable from general partner for the commodity derivatives that were internally allocated to the drilling partnership. The receivables are based upon the fair values of the internally allocated derivative contracts to the drilling partnership as of the balance sheet date. These derivative contracts meet the criteria of being accounted for as derivative instruments (hedges) and which are expected to be converted into cash or otherwise disposed of within a year or the normal operating cycle, if longer, net of the effects of the master netting arrangements.
Carrying value as of the balance sheet date of obligations incurred and payable, pertaining to costs that are statutory in nature, are incurred on contractual obligations, or accumulate over time and for which invoices have not yet been received or will not be rendered. Examples include taxes, interest, rent and utilities. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).
Accumulated change, net of tax, in accumulated gains and losses from derivative instruments designated and qualifying as the effective portion of cash flow hedges. Includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 26
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The carrying amount of a liability for an asset retirement obligation. An asset retirement obligation is a legal obligation associated with the disposal or retirement of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.
-Name Statement of Financial Accounting Standard (FAS)
-Number 143
-Paragraph 3, 10, 22
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Sum of the carrying amounts as of the balance sheet date of all assets that are recognized. Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.
-Name Statement of Financial Accounting Concepts (CON)
-Number 6
-Paragraph 25
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Sum of the carrying amounts as of the balance sheet date of all assets that are expected to be realized in cash, sold, or consumed within one year (or the normal operating cycle, if longer). Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.
Includes currency on hand as well as demand deposits with banks or financial institutions. It also includes other kinds of accounts that have the general characteristics of demand deposits in that the Entity may deposit additional funds at any time and also effectively may withdraw funds at any time without prior notice or penalty. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present minimal risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased three years ago does not become a cash equivalent when its remaining maturity is three months. Compensating balance arrangements that do not legally restrict the withdrawal or usage of cash amounts may be reported as Cash and Cash Equivalents, while legally restricted deposits held as compensating balances against borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular deposits are not generally reported as cash and cash equivalents. Includes cash and cash equivalents associated with the entity's continuing operations. Excludes cash and cash equivalents associated with the disposal group (and discontinued operation).
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 7
-Footnote 1
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-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 8, 9
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-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 7, 26
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The aggregate amount of receivables to be collected from related parties where one party can exercise control or significant influence over another party; including affiliates, owners or officers and their immediate families, pension trusts, and so forth, at the financial statement date. which are usually due within one year (or one business cycle).
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 2
-Subparagraph d
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Aggregate amount of receivables to be collected from related parties where one party can exercise control or significant influence over another party; including affiliates, owners or officers and their immediate families, pension trusts, and so forth, at the financial statement date. which are usually due after one year (or one business cycle).
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 2
-Subparagraph d
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Total of all Liabilities and Stockholders' Equity items (or Partners' Capital, as applicable), including the portion of equity attributable to noncontrolling interests, if any.
Total obligations incurred as part of normal operations that are expected to be paid during the following twelve months or within one business cycle, if longer.
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Oil and gas properties net of accumulated depreciation, depletion, amortization, impairment, and abandonment, carried under the successful effort method.
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