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EX-31.2 - EX-31.2 - Atlas America Series 26-2005 L.P.ser26-ex312_201409308.htm
EX-32.1 - EX-32.1 - Atlas America Series 26-2005 L.P.ser26-ex321_201409307.htm

 

 

 

United States

Securities and Exchange Commission

Washington, D.C. 20549

 

Form 10-Q

 

(Mark One)

þ

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

¨

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

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

Park Place Corporate Center One

 

 

1000 Commerce Drive, 4th Floor

 

 

Pittsburgh, PA

 

15275

(Address of principal executive offices)

 

(zip code)

Issuer’s telephone number, including area code: (412)-489-0006

 

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  ¨

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  ¨

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

 

¨

  

Accelerated filer

 

¨

 

 

 

 

 

 

 

Non-accelerated filer

 

¨

  

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  ¨     No  þ

 

 

 

 

 

 


 

ATLAS AMERICA SERIES 26-2005 L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

 

 

 

PAGE

PART I.

FINANCIAL INFORMATION (Unaudited)

 

 

Item 1:

 

 

 

 

Condensed Balance Sheets as of September 30, 2014 and December 31, 2013

3

 

 

Condensed Statements of Operations for the Three and Nine Months ended September 30, 2014 and 2013

4

 

 

Condensed Statements of Comprehensive (Loss) Income for the Three and Nine Months ended September 30, 2014 and 2013

5

 

 

Condensed Statement of Changes in Partners’ Capital for the Nine Months ended September 30, 2014

6

 

 

Condensed Statements of Cash Flows for the Nine Months ended September 30, 2014 and 2013

7

 

 

Notes to Condensed Financial Statements

8

Item 2:

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

18

Item 4:

 

Controls and Procedures

22

PART II.

 

OTHER INFORMATION

 

Item 1:

 

Legal Proceedings

23

Item 6:

 

Exhibits

24

 

SIGNATURES

25

 

CERTIFICATIONS

 

 

 

 

2


 

PART I. FINANCIAL INFORMATION

ITEM I. FINANCIAL STATEMENTS

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

 

 

September 30,
2014

 

  

  

December 31,
2013

 

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

-

 

 

$

43,700

 

Accounts receivable trade–affiliate

 

174,000

 

 

 

319,600

 

Asset retirement receivable-affiliate

 

18,200

 

 

 

-

 

Accounts receivable monetized gains – affiliate

 

-

 

 

 

11,000

 

Current portion of derivative assets

 

2,500

 

 

 

1,300

 

Total current assets

 

194,700

 

 

 

375,600

 

 

Oil and gas properties, net

 

3,335,300

 

 

 

3,478,500

 

Long-term derivative assets

 

5,300

 

 

 

6,900

 

 

$

3,535,300

 

 

$

3,861,000

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accrued liabilities

$

7,100

 

 

$

7,900

 

Payable to limited partners

 

-

 

 

 

88,700

 

Current portion of put premiums payable-affiliate

 

2,500

 

 

 

-

 

Total current liabilities

 

9,600

 

 

 

96,600

 

 

Long-term put premiums payable-affiliate

 

8,100

 

 

 

12,300

 

Asset retirement obligation

 

2,155,500

 

 

 

2,063,900

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

Partners’ capital:

 

 

 

 

 

 

 

Managing general partner’s interest

 

889,400

 

 

 

978,800

 

Limited partners’ interest (1,400 units)

 

479,200

 

 

 

718,800

 

Accumulated other comprehensive loss

 

(6,500

)

 

 

(9,400

)

Total partners’ capital

 

1,362,100

 

 

 

1,688,200

 

 

$

3,535,300

 

 

$

3,861,000

 

See accompanying notes to condensed financial statements.

 

 

 

3


 

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

Three Months Ended
September 30,

 

 

Nine Months Ended
September 30,

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas and oil

$

174,200

 

 

$

322,000

 

 

$

854,100

 

 

$

947,100

 

Total revenues

 

174,200

 

 

 

322,000

 

 

 

854,100

 

 

 

947,100

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production

 

160,500

 

 

 

184,900

 

 

 

508,600

 

 

 

536,200

 

Depletion

 

47,000

 

 

 

141,000

 

 

 

143,200

 

 

 

411,000

 

Accretion of asset retirement obligation

 

30,600

 

 

 

29,100

 

 

 

91,900

 

 

 

87,100

 

General and administrative

 

32,400

 

 

 

38,600

 

 

 

95,200

 

 

 

113,800

 

Total costs and expenses

 

270,500

 

 

 

393,600

 

 

 

838,900

 

 

 

1,148,100

 

Net (loss) income

$

(96,300

)

 

$

(71,600

)

 

$

15,200

 

 

$

(201,000

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Allocation of net (loss) income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Managing general partner

$

(28,400

)

 

$

(7,900

)

 

$

25,200

 

 

$

(18,500

)

Limited partners

$

(67,900

)

 

$

(63,700

)

 

$

(10,000

)

 

$

(182,500

)

Net loss per limited partnership unit

$

(48

)

 

$

(46

)

 

$

(7

)

 

$

(130

)

See accompanying notes to condensed financial statements.

 

 

 

4


 

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)

 

 

Three Months Ended
September 30,

 

 

Nine Months Ended
September 30,

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

$

(96,300

)

 

$

(71,600

)

 

$

15,200

 

 

$

(201,000

)

Other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized holding gain (loss) on cash flow hedging contracts

 

3,400

 

 

 

2,300

 

 

 

(6,100

)

 

 

(8,800

)

Difference in estimated hedge gains receivable

 

(1,000

)

 

 

5,000

 

 

 

15,900

 

 

 

21,400

 

Reclassification adjustment for losses (gains) realized in net loss from cash flow hedges

 

500

 

 

 

(3,600

)

 

 

(6,900

)

 

 

(7,600

)

Total other comprehensive income

 

2,900

 

 

 

3,700

 

 

 

2,900

 

 

 

5,000

 

Comprehensive (loss) income

$

(93,400

)

 

$

(67,900

)

 

$

18,100

 

 

$

(196,000

)

See accompanying notes to condensed financial statements.

 

 

 

5


 

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE NINE MONTHS ENDED

September 30, 2014

(Unaudited)

 

 

Managing
General
Partner

 

 

Limited
Partners

 

 

Accumulated
Other
Comprehensive
Loss

 

 

Total

 

Balance at December 31, 2013

$

978,800

 

 

$

718,800

 

 

$

(9,400

)

 

$

1,688,200

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Participation in revenues and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net production revenues

 

126,000

 

 

 

219,500

 

 

 

-

 

 

 

345,500

 

Depletion

 

(33,200

)

 

 

(110,000

)

 

 

-

 

 

 

(143,200

)

Accretion of asset retirement obligation

 

(33,200

)

 

 

(58,700

)

 

 

-

 

 

 

(91,900

)

General and administrative

 

(34,400

)

 

 

(60,800

)

 

 

-

 

 

 

(95,200

)

Net income (loss)

 

25,200

 

 

 

(10,000

)

 

 

-

 

 

 

15,200

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income

 

-

 

 

 

-

 

 

 

2,900

 

 

 

2,900

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions to partners

 

(114,600

)

 

 

(229,600

)

 

 

-

 

 

 

(344,200

)

 

Balance at September 30, 2014

$

889,400

 

 

$

479,200

 

 

$

(6,500

)

 

$

1,362,100

 

See accompanying notes to condensed financial statements.

 

 

 

6


 

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

Nine Months Ended
September 30,

 

2014

 

  

2013

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

$

15,200

 

 

$

(201,000

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Depletion

 

143,200

 

 

 

411,000

 

Non cash loss on derivative value

 

12,600

 

 

 

62,900

 

Accretion of asset retirement obligation

 

91,900

 

 

 

87,100

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Increase in accounts receivable trade – affiliate

 

145,600

 

 

 

(67,700

)

Increase in accrued liabilities

 

(800

)

 

 

11,500

 

Decrease in payables to limited partners

 

(88,700

)

 

 

-

 

Asset retirement receivable-affiliate

 

(18,200

)

 

 

-

 

Asset retirement obligations settled

 

(300

)

 

 

(26,400

)

Net cash provided by operating activities

 

300,500

 

 

 

277,400

 

 

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Proceeds from sale of tangible equipment

 

-

 

 

 

10,400

 

Net cash provided by investing activities

 

-

 

 

 

10,400

 

 

 

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

 

 

Distributions to partners

 

(344,200

)

 

 

(321,600

)

Net cash used in financing activities

 

(344,200

)

 

 

(321,600

)

 

Net decrease in cash and cash equivalents

 

(43,700

)

 

 

(33,800

)

Cash and cash equivalents at beginning of period

 

43,700

 

 

 

33,800

 

Cash and cash equivalents at end of period

$

-

 

 

$

-

 

See accompanying notes to condensed financial statements.

 

 

 

7


 

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

 

NOTE 1 – DESCRIPTION OF BUSINESS

Atlas America Series 26-2005 L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 26, 2005 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

On October 13, 2014, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), and its midstream subsidiary, Atlas Pipeline Partners, L.P. (“APL”), entered into definitive agreements to be acquired by Targa Resources Corp. and Targa Resources Partners LP, respectively. Immediately prior to the acquisition, Atlas Energy will distribute to its unitholders 100% of the limited liability company interests in ARP’s general partner, which has changed its name to Atlas Energy Group, LLC (“New Atlas”) and will become a separate, publicly traded company as a result of the distribution. New Atlas will hold all of Atlas Energy’s non-midstream holdings, which includes the Partnership’s business as well as the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in ARP.

In March 2012, Atlas Energy contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.

On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of 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, 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”).

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The accompanying condensed financial statements, which are unaudited, except for the condensed balance sheet at December 31, 2013, which 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 Partnership’s 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, 2013. The results of operations for the three and nine months ended September 30, 2014 may not necessarily be indicative of the results of operations for the year ended December 31, 2014.

 

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. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

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, 2013 filed with the Securities and Exchange Commission (“SEC”).


8


 

Use of Estimates

Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues 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, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition” 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 customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September 30, 2014 and December 31, 2013, 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 that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six million cubic feet (“mcf”) of natural gas.

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 cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $143,200 and $411,000 for the nine months ended September 30, 2014 and 2013, respectively.

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.

The following is a summary of oil and gas properties at the dates indicated:

 

 

September 30,
2014

 

 

December 31,
2013

 

Proved properties:

 

 

 

 

 

 

 

Leasehold interests

$

1,102,500

 

 

$

1,102,500

 

Wells and related equipment

 

43,608,100

 

 

 

43,608,100

 

Total natural gas and oil properties

 

44,710,600

 

 

 

44,710,600

 

Accumulated depletion and impairment

 

(41,375,300

)

 

 

(41,232,100

)

Oil and gas properties, net

$

3,335,300

 

 

$

3,478,500

 

 

 


9


 

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 of 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, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the 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 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 available additional information which could cause the assumption to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. There were no oil and gas properties impairment recorded for the three and nine months ended September 30, 2014 and 2013 or during the year ended December 31, 2013.

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. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are 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 its percentage ownership of working interest and/or overriding royalty.


10


 

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil and condensate 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 and compression fees, which are, in turn, based upon applicable product prices. During the current quarter, the Partnership identified a material weakness in its revenue recognition process (See Item 4: Controls and Procedures). As a result of the weakness, the Partnership overestimated its June 30, 2014 unbilled revenues by $24,700. As a result, revenue and net income is overstated by $24,700 for the three and six months ended June 30, 2014. In adjusting for the overstatement of revenue and net income that existed at June 30, 2014, during the third quarter of 2014 revenue is understated by $24,700 and net loss is overstated for the three month period ended September 30, 2014. In addition, there was no impact on Partnership distributions. As of September 30, 2014, the weakness has been remediated and the Partnership had unbilled revenues at September 30, 2014 and December 31, 2013 of $104,600 and $166,000, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive (Loss) Income

Comprehensive (loss) income includes net (loss) income and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net (loss) income. These changes, other than net (loss) income, are referred to as “other comprehensive income” and, for the Partnership, include changes in the fair value of derivative contracts accounted for as cash flow hedges.

 

Recently Adopted Accounting Standards

In February 2013, the Financial Accounting Standards Board (the “FASB”) issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

 

Recently Issued Accounting Standards

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

11


 

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other), are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.  

 

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 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 cost estimates, remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The associated asset retirement costs from revisions are capitalized as part of the carrying amount of the long-lived asset. 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.

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of September 30, 2014, the MGP withheld $18,200 of net production revenue for future plugging and abandonment costs.

A reconciliation of the Partnership’s liability for plugging and abandonment costs for the periods indicated is as follows:

 

 

Three Months Ended
September 30,

 

 

Nine Months Ended
September 30,

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset retirement obligation at beginning of period

$

2,124,900

 

 

$

2,170,200

 

 

$

2,063,900

 

 

$

2,134,500

 

Liabilities settled

 

-

 

 

 

(4,100

)

 

 

(300

)

 

 

(26,400

)

Accretion expense

 

30,600

 

 

 

29,100

 

 

 

91,900

 

 

 

87,100

 

Asset retirement obligation at end of period

$

2,155,500

 

 

$

2,195,200

 

 

$

2,155,500

 

 

$

2,195,200

 

 

12


 

NOTE 4 – DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales 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 commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, 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 the MGP determines that a derivative is not effective as a hedge or that it has 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 will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to the Partnership’s commodity derivatives to gas and oil production revenues within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur.

 


13


 

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $7,800 and $8,200 at September 30, 2014 and December 31, 2013, respectively.

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

At September 30, 2014, the Partnership had the following commodity derivatives:

Natural Gas Put Options

 

Production
Period Ending
December 31,

  

Volumes

 

  

Average
Fixed Price

 

  

Fair Value
Asset (2)

 

 

  

(MMBtu) (1)

 

  

(per MMBtu) (1)

 

  

 

 

2014

 

 

2,700

 

 

$

3.80

 

 

$

100

 

2015

 

 

8,600

 

 

 

4.00

 

 

 

3,300

 

2016

 

 

8,600

 

 

 

4.15

 

 

 

4,400

 

 

 

 

 

 

 

 

 

 

 

$

7,800

 

 

 

(1)

“MMBtu” represents million British Thermal Units.

(2)

Fair value based on forward NYMEX natural gas prices, as applicable.

Effects of Derivative Instruments on Statements of Operations:

The following table summarizes the gain or loss recognized in the statements of operations for the three and nine months ended September 30, 2014 and 2013:

 

 

Three Months Ended
September 30,

 

 

Nine Months Ended
September 30,

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

(Loss) gain from cash flow hedges reclassified from accumulated other comprehensive income into natural gas, oil and liquids revenues

$

(500

)

 

$

3,600

 

 

$

6,900

 

 

$

7,600

 

 

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.


14


 

Monetized Gains

At September 30, 2014 and December 31, 2013, remaining hedge monetization cash proceeds of $3,400 and $17,200, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At September 30, 2014 and December 31, 2013, the put premiums were recorded as short-term payables to affiliate of $5,900 and $6,200, respectively, and long-term payables to affiliate of $8,100 and $12,300, respectively.

The following table summarizes the gross and net fair values of the Partnership’s affiliate balances on the Partnership’s balance sheets for the periods indicated:

 

 

 

Gross Amounts
of Recognized
Assets

 

 

Gross Amounts
Offset in the
Balance Sheets

 

 

Net Amount of
Assets
Presented in the
Balance Sheets

 

Offsetting Assets

 

 

 

 

 

 

 

 

 

 

 

 

As of September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable monetized gains-affiliate

 

$

3,400

 

 

$

(3,400

)

 

$

-

 

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable monetized gains-affiliate

 

$

17,200

 

 

$

(6,200

)

 

$

11,000

 

 

 

 

Gross Amounts
of Recognized
Liabilities

 

 

Gross Amounts
Offset in the
Balance Sheets

 

 

Net Amount of
Liabilities
Presented in the
Balance Sheets

 

Offsetting Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

As of September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Put premiums payable-affiliate

 

$

(5,900

)

 

$

3,400

 

 

$

(2,500

)

Long-term put premiums payable-affiliate

 

 

(8,100

)

 

 

-

 

 

 

(8,100

)

 

Total

 

$

(14,000

)

 

$

3,400

 

 

$

(10,600

)

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Put premiums payable-affiliate

 

$

(6,200

)

 

$

6,200

 

 

$

-

 

Long-term put premiums payable-affiliate

 

 

(12,300

)

 

 

-

 

 

 

(12,300

)

 

Total

 

$

(18,500

)

 

$

6,200

 

 

$

(12,300

)

 


15


 

Accumulated Other Comprehensive Loss

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized losses recognized in loss in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheet in accumulated other comprehensive loss of $6,500 as of September 30, 2014. Included in accumulated other comprehensive loss are unrealized gains of $3,700, net of the MGP interest, that were recognized as a result of oil and gas property impairments during prior periods. During the nine months ended September 30, 2014, $3,200 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $6,500 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $3,700 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining $2,800 in later periods.

 

NOTE 5 – 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. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted 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 entity’s own assumptions about the assumptions 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 carrying values of cash, accounts receivable and accounts payable approximate their respective fair values due to the short term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

 


16


 

Information for assets and liabilities measured at fair value at September 30, 2014 and December 31, 2013 is as follows:

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

As of September 30, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity puts

 

$

-

 

 

$

7,800

 

 

$

-

 

 

$

7,800

 

Derivative liabilities, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity puts

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Total derivatives, fair value, net

 

$

-

 

 

$

7,800

 

 

$

-

 

 

$

7,800

 

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity puts

 

$

-

 

 

$

8,200

 

 

$

-

 

 

$

8,200

 

Derivative liabilities, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity puts

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Total derivatives, fair value, net

 

$

-

 

 

$

8,200

 

 

$

-

 

 

$

8,200

 

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding 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). There were no assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2014 and 2013.

 

NOTE 6 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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. Monthly well supervision fees, which are included in production expense in the Partnership’s statement of operations, are payable at $318 per well per month for operating and maintaining the wells. 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. Direct costs, which are included in production and general administrative expense in the Partnership’s statements of operations, are payable to the MGP and its affiliates as a reimbursement for all costs expended on the Partnership’s behalf.

The following table provides information with respect to these costs and the periods incurred:

 

 

Three Months Ended
September 30,

 

 

Nine Months Ended
September  30,

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Administrative fees

$

19,700

 

 

$

20,700

 

 

$

60,700

 

 

$

64,300

 

Supervision fees

 

82,100

 

 

 

86,800

 

 

 

253,400

 

 

 

268,800

 

Transportation fees

 

20,300

 

 

 

38,500

 

 

 

94,500

 

 

 

117,400

 

Direct costs

 

70,800

 

 

 

77,500

 

 

 

195,200

 

 

 

199,500

 

Total

$

192,900

 

 

$

223,500

 

 

$

603,800

 

 

$

650,000

 

 


17


 

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. Payable to limited partners on the Partnership’s balance sheets at December 31, 2013 includes $88,700, related to a refund of state income tax withholdings, payable to limited partners only.

 

NOTE 7 – COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of September 30, 2014, the MGP withheld $18,200 of net production revenue for future plugging and abandonment costs.

Legal Proceedings

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

 

 

ITEM  2.

MANAGEMENT’S 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. Such statements are subject to certain risks and uncertainties, which 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.

General

Atlas America Series 26-2005 L.P. (“we”, “us”, or the “Partnership”) is a Delaware limited partnership, formed on May 26, 2005 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

 

On October 13, 2014, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), and its midstream subsidiary, Atlas Pipeline Partners, L.P. (“APL”), entered into definitive agreements to be acquired by Targa Resources Corp. and Targa Resources Partners LP, respectively. Immediately prior to the acquisition, Atlas Energy will distribute to its unitholders 100% of the limited liability company interests in ARP’s general partner, which has changed its name to Atlas Energy Group, LLC (“New Atlas”) and will become a separate, publicly traded company as a result of the distribution. New Atlas will hold all of Atlas Energy’s non-midstream holdings, which includes the Partnership’s business as well as the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in ARP.

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, for administrative services.

We intend to continue to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.


18


 

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 and/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 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, 2014, our MGP withheld $18,200 of net production revenue for this purpose.

Markets and Competition

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 2014 and 2013, 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.


19


 

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
September 30,

 

 

Nine Months Ended
September 30,

 

 

2014

 

 

2013

 

 

2014

 

 

2013

 

Production revenues (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas

$

149

 

 

$

275

 

 

$

719

 

 

$

819

 

Oil

 

25

 

 

 

47

 

 

 

135

 

 

 

128

 

Total

$

174

 

 

$

322

 

 

$

854

 

 

$

947

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas (mcf/day) (1)

 

667

 

 

 

789

 

 

 

651

 

 

 

768

 

Oil (bbl/day) (1)

 

3

 

 

 

4

 

 

 

5

 

 

 

5

 

Total (mcfe/day) (1)

 

685

 

 

 

813

 

 

 

681

 

 

 

798

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales prices: (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas (per mcf) (1) (3) (4)

$

2.91

 

 

$

4.04

 

 

$

4.12

 

 

$

4.21

 

Oil (per bbl) (1)

$

83.72

 

 

$

113.08

 

 

$

92.15

 

 

$

94.04

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As a percent of revenues (4)

 

81

%

 

 

57

%

 

 

60

%

 

 

57

%

Per mcfe (1)

$

2.54

 

 

$

2.46

 

 

$

2.73

 

 

$

2.46

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depletion per mcfe

$

0.75

 

 

$

1.88

 

 

$

0.77

 

 

$

1.89

 

 

 

(1)

Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to mcfe using the ratio of six mcfs to one bbl.

(2)

Average sales prices represent accrual basis pricing after adjusting for the effect of previously recognized gains resulting from prior period impairment charges.

(3)

Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $4,200 and $18,300 for the three months ended September 30, 2014 and 2013, respectively. Previously recognized derivative gains were $12,500 and $63,200 for the nine months ended September 30, 2014 and 2013, respectively.

(4)

The average sales price and production costs as a percent of revenues for natural gas for the three months ended September 30, 2014 has been adjusted to reflect $24,700 of additional revenue, (See Item 4: Controls and Procedures) for additional information.

Natural Gas Revenues. During the current year quarter, management identified a material weakness in the process used to estimate our unbilled revenue (See Item 4: Controls and Procedures). As a result, natural gas revenue for the three months ending September 30, 2014 includes an adjustment to reduce natural gas revenue by $24,700. The adjustment is the result of overestimating our unbilled revenues as of June 30, 2014. Our unadjusted natural gas revenues were $174,200 and $275,400 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $101,200 (37%). The $101,200 decrease in natural gas revenues for the three months ended September 30, 2014 as compared to the prior year similar period was attributable to an $58,500 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions and a $42,700 decrease in production volumes. Our production volumes decreased to 667 mcf per day for the three months ended September 30, 2014 from 789 mcf per day for the three months ended September 30, 2013, a decrease of 122 mcf per day (15%). The overall decrease in natural gas production is primarily due to the normal decline inherent in the life of a well.

Our natural gas revenues were $719,500 and $818,900 for the nine months ended September 30, 2014 and 2013, respectively, a decrease of $99,400 (12%). The $99,400 decrease in natural gas revenues for the nine months ended September 30, 2014 as compared to the prior year similar period was attributable to a $125,400 decrease in production volumes, partially offset by a $26,000 increase in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions including the reversal of $12,500 and $63,200 previously recognized derivative gains for the nine months ended September 30, 2014 and 2013, respectively. Our production volumes decreased to 651 mcf per day for the nine months ended September 30, 2014 from 768 mcf per day for the nine months ended September 30, 2013, a decrease of 117 mcf per day (15%). The overall decrease in natural gas production is primarily due to the normal decline inherent in the life of a well.


20


 

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $24,700 and $46,600 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $21,900 (47%). The $21,900 decrease in oil revenues for the three months ended September 30, 2014 as compared to the prior year similar period was attributable to a $13,300 decrease in production volumes and an $8,600 decrease in oil prices after the effect of financial hedges. Our production volumes decreased to 3 bbls per day for the three months ended September 30, 2014 from 4 bbls per day for the three months ended September 30, 2013, a decrease of 1 bbls per day (25%).

Our oil revenues were $134,600 and $128,200 for the nine months ended September 30, 2014 and 2013, respectively, an increase of $6,400 (5%). The $6,400 increase in oil revenues for the nine months ended September 30, 2014 as compared to the prior year similar period was attributable to a $9,200 increase in production volumes, partially offset by a $2,800 decrease in oil prices after the effect of financial hedges. Our production volumes increased to 5.35 bbls per day for the nine months ended September 30, 2014 from 5 bbls per day for the nine months ended September 30, 2013, an increase of 0.35 bbls per day (7%).

Costs and Expenses. Production expenses were $160,500 and $184,900 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $24,400 (13%). Production expenses were $508,600 and $536,200 for the nine months ended September 30, 2014 and 2013, respectively, a decrease of $27,600 (5%). The decrease for the three and nine months ended September 30, 2014 was mostly due to lower transportation and operating fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 27% and 44% for the three months ended September 30, 2014 and 2013, respectively, and 17% and 43% for the nine months ended September 30, 2014 and 2013, respectively. These changes are primarily attributable to changes in oil and gas reserve quantities and to a lesser extent revenues, product prices and 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, 2014 and 2013 were $32,400 and $38,600, respectively, a decrease of $6,200 (16%). For the nine months ended September 30, 2014 and 2013, these expenses were $95,200 and $113,800, respectively, a decrease of $18,600 (16%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The changes for the three and nine months ended September 30, 2014 are primarily due to third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities increased $23,100 in the nine months ended September 30, 2014 to $300,500 as compared to $277,400 for the nine months ended September 30, 2013. This increase was primarily due to an increase in the change in accounts receivable trade-affiliate of $213,300 and a change in asset retirement obligations settled of $26,100. The increase was partially offset by a decrease in net income before depletion, accretion, and non-cash loss on derivative value of $97,100, a decrease in the change in accrued liabilities of $12,300, the change in limited partner payable of $88,700, and the change in asset retirement receivable-affiliate of $18,200 for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.

Cash provided by investing activities was $10,400 for the nine months ended September 30, 2013, for proceeds from a sale of tangible equipment.

Cash used in financing activities increased $22,600 during the nine months ended September 30, 2014 to $344,200 from $321,600 for the nine months ended September 30, 2013. This increase was due to an increase in cash distributions to partners.

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 at any one time 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.


21


 

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is 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 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, 2013.

 

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 SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our 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 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 on that evaluation, our Chief Executive Officer, President and Chief Financial Officer concluded that, as of September 30, 2014, our disclosure controls and procedures were effective at the reasonable assurance level.

During the current period, but before the June 30, 2014 Form 10-Q was filed, management identified a deficiency in our disclosure controls and procedures. Language indicating management’s conclusion on the Company’s internal control over financial reporting as of December 31, 2013 was not included in Management’s Report on Internal Control over Financial Reporting within Form 10-K, Item 9A. “Controls and Procedures.” As a result of the amendment required to our December 31, 2013 Form 10-K, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer concluded that, as of June 30, 2014, our disclosure controls and procedures were not effective at the reasonable assurance level.

As of the date of filing of this Form 10-Q, management has implemented a more formal and thorough review of its disclosures in Form 10-K, Item 9A and Form 10-Q, Item 4:  Controls and Procedures. As of the date of filing of this Form 10-Q, management believes the deficiency in the Partnership’s disclosure controls and procedures has been remediated.

Changes in Internal Control over Financial Reporting

During the current quarter, management identified a material weakness in the process used to estimate the June 30, 2014 unbilled revenue. The weakness resulted from an insufficient review of contract pricing information used to estimate unbilled revenue. As a result, a change in a pricing index of a marketing contract that was not properly reflected in the estimate of unbilled revenues. At June 30, 2014, the Partnership overestimated its unbilled revenues by $24,700 and the adjustment had no impact on cash distributions.

As of the date of filing this Form 10-Q, management has implemented a more formal and thorough review of its pricing inputs used to calculate the estimated unbilled revenue. As of the date of filing of this Form 10-Q, management believes the deficiency in the Partnership’s internal control over financial reporting has been remediated.

Other than as previously discussed, there have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


22


 

PART II OTHER INFORMATION

 

ITEM  1.

LEGAL PROCEEDINGS

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

 

 

 

23


 

ITEM  6.

EXHIBITS

EXHIBIT INDEX

 

Exhibit No.

  

Description

 

  3.1

  

 

Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 26-2005 L.P. (1)

  3.2

 

Agreement of Limited Partnership (1)

31.1

  

Certification Pursuant to Rule 13a-14/15(d)-14

31.2

  

Certification Pursuant to Rule 13a-14/15(d)-14

32.1

  

Section 1350 Certification

32.2

  

Section 1350 Certification

101

  

Interactive Data File

 

 

(1)

Filed on April 28, 2006 in the Form S-1 Registration Statement dated April 28, 2006, File No. 000-51945

 

 

 

24


 

SIGNATURES

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 14, 2014

 

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 persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Date: November 14, 2014

 

By: 

/s/ SEAN P. MCGRATH

 

 

 

Sean P. McGrath,

Chief Financial Officer

 

25