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

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

Commission file number: 001-32169

ATLAS ENERGY, INC.

(Exact name of registrant as specified in its charter)

DELAWARE (State or other jurisdiction of incorporation or organization)		51-0404430 (I.R.S. Employer Identification No.)
1550 Coraopolis Heights Road Moon Township, Pennsylvania (Address of principal executive office)		15108 (Zip code)

Registrant’s telephone number, including area code:(412) 262-2830

ATLAS AMERICA, INC.

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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” and “smaller reporting company” in rule 12b-2 of the Exchange Act.

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if smaller reporting company)

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

The number of outstanding shares of the registrant’s common stock on November 6, 2009 was 78,131,951 shares.

 

 

ATLAS ENERGY, INC. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q

		PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008			3
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008			4
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2009			6
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008			7
Notes to Consolidated Financial Statements			9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			63
Item 3. Quantitative and Qualitative Disclosures About Market Risk			90
Item 4. Controls and Procedures			100
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			101
Item 1A. Risk Factors			102
Item 4. Submission of Matters to a Vote of Security Holders			102
Item 6. Exhibits			103
SIGNATURES			107
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, INC. AND SUBSIDIARIES

		September 30,				December 31,
		2009				2008
ASSETS
Current assets:
Cash and cash equivalents		$	35,693			$	104,496
Accounts receivable			145,548				169,405
Current portion of derivative receivable from Partnerships			346				3,022
Current portion of derivative asset			88,960				152,726
Prepaid expenses and other			27,900				25,464
Prepaid and deferred income taxes			881				32,215
Current assets of discontinued operations			—				13,441
Total current assets			299,328				500,769
Property, plant and equipment, net			3,708,389				3,744,815
Intangible assets, net			177,539				197,485
Goodwill, net			35,166				35,166
Long-term derivative receivable from Partnerships			4,740				2,719
Long term derivative asset			42,405				69,451
Investment in joint venture			133,740				—
Other assets, net			70,419				53,311
Long-term assets of discontinued operations			—				242,165
		$	4,471,726			$	4,845,881
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt		$	12,000			$	—
Accounts payable			105,929				140,725
Liabilities associated with drilling contracts			16,590				96,883
Accrued producer liabilities			45,539				66,846
Current portion of derivative payable to Partnerships			23,173				34,933
Current portion of derivative liability			46,570				73,776
Accrued liabilities			165,391				103,383
Advances from affiliate			219				108
Current liabilities of discontinued operations			—				10,572
Total current liabilities			415,411				527,226
Long-term debt, less current portion			2,115,505				2,413,082
Deferred tax liability			51,158				242,058
Long-term derivative payable to Partnerships			17,021				22,581
Long-term derivative liability			33,847				59,103
Other long-term liabilities			54,941				52,263
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares			—				—
Common stock, $0.01 par value: 114,000,000 authorized shares			814				426
Additional paid-in capital			1,137,546				412,869
Treasury stock, at cost			(143,362	)			(147,621	)
Accumulated other comprehensive income			50,351				21,143
Retained earnings			136,027				124,698
			1,181,376				411,515
Non-controlling interests			602,467				1,118,053
Total stockholders’ equity			1,783,843				1,529,568
		$	4,471,726			$	4,845,881

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)

(Unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Revenues:
Well construction and completion		$	81,496			$	116,987			$	257,231			$	343,466
Gas and oil production			65,986				81,235				207,908				236,417
Transmission, gathering and processing			205,603				410,942				555,373				1,218,359
Administration and oversight			3,149				5,216				9,644				15,370
Well services			5,012				5,299				14,911				15,363
Gain on asset sales			55				—				105,746				—
Gain (loss) on mark-to-market derivatives			1,032				147,505				(17,245	)			(257,344	)
Other, net			4,851				3,818				11,696				11,842
Total revenues			367,184				771,002				1,145,264				1,583,473
Costs and expenses:
Well construction and completion			69,138				101,727				218,236				298,666
Gas and oil production			12,128				12,688				33,217				35,735
Transmission, gathering and processing			167,862				333,988				470,752				992,504
Well services			2,378				2,753				6,922				7,815
General and administrative			31,786				12,392				80,777				57,903
Net expense reimbursement — affiliate			280				255				842				689
Depreciation, depletion and amortization			46,460				44,325				147,427				129,539
Total costs and expenses			330,032				508,128				958,173				1,522,851
Operating income			37,152				262,874				187,091				60,622
Interest Expense			(47,754	)			(37,331	)			(124,322	)			(106,538	)
Income (loss) from continuing operations before income taxes (benefit)			(10,602	)			225,543				62,769				(45,916	)
Provision (benefit) for income taxes			(716	)			13,647				5,555				12,288
Net income (loss) from continuing operations			(9,886	)			211,896				57,214				(58,204	)
Discontinued operations:
Gain on sale of discontinued operations (net of income taxes of $2,228 for the nine months ended September 30, 2009)			—				—				48,851				—
Income from discontinued operations (net of income taxes of $277 for the three months ended September 30, 2008 and $498 and $848 for the nine months ended September 30, 2009 and 2008, respectively)			—				6,261				10,918				20,181
Net income (loss)			(9,886	)			218,157				116,983				(38,023	)
(Income) loss attributable to non-controlling interests			9,172				(194,054	)			(103,686	)			60,777
Net income (loss) attributable to common shareholders		$	(714	)		$	24,103			$	13,297			$	22,754

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Net income (loss) attributable to common shareholders per share — basic:
Income (loss) from continuing operations attributable to common shareholders		$	(0.02	)		$	0.59			$	0.23			$	0.54
Discontinued operations attributable to common shareholders			0.00				0.01				0.11				0.03
Net income (loss) attributable to common shareholders		$	(0.02	)		$	0.60			$	0.34			$	0.57
Net income (loss) attributable to common shareholders per share — diluted:
Income (loss) from continuing operations attributable to common shareholders		$	(0.02	)		$	0.57			$	0.22			$	0.51
Discontinued operations attributable to common shareholders			0.00				0.01				0.11				0.03
Net income (loss) attributable to common shareholders		$	(0.02	)		$	0.58			$	0.33			$	0.54
Weighted average common shares outstanding:
Basic			39,780				40,093				39,460				40,251
Diluted			39,780				41,994				40,051				42,121
Income (loss) attributable to common shareholders:
Income (loss) from continuing operations (net of income taxes (benefit) of $(716) and $13,647 for the three months ended September 30, 2009 and 2008, respectively, and $5,555 and $12,288 for the nine months ended September 30, 2009 and 2008, respectively)		$	(714	)		$	23,670			$	9,044			$	21,431
Discontinued operations (net of income taxes of $277 for the three months ended September 30, 2008, and $2,726 and $848 for the nine months ended September 30, 2009 and 2008, respectively)			—				433				4,253				1,323
Net income (loss) attributable to common shareholders		$	(714	)		$	24,103			$	13,297			$	22,754

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009

(in thousands, except share data)
(Unaudited)

																						Accumulated
										Additional												Other								Non-				Total
		Common Stock								Paid-In				Treasury Stock								Comprehensive				Retained				controlling				Stockholders’
		Shares				Amount				Capital				Shares				Amount				Income				Earnings				Interests				Equity
Balance at January 1, 2009			42,503,119			$	426			$	412,869				(3,252,861	)		$	(147,621	)		$	21,143			$	124,698			$	1,118,053			$	1,529,568
Common stock issuance			24,425				—				(2,684	)			98,829				4,259				—				—				—				1,575
Other comprehensive income			—				—				—				—				—				29,208				—				(14,230	)			14,978
Stock option and unit compensation expense			(40,600	)			—				2,550				—				—				—				—				—				2,550
Merger with Atlas Energy Resources LLC			38,776,768				388				724,811				—				—				—				—				(556,384	)			168,815
Dividends paid			—				—				—				—				—				—				(1,968	)			—				(1,968	)
Distributions to non-controlling interests			—				—				—				—				—				—				—				(43,799	)			(43,799	)
Non-controlling interests’ capital contributions			—				—				—				—				—				—				—				(4,859	)			(4,859	)
Net income			—				—				—				—				—				—				13,297				103,686				116,983
Balance at September 30, 2009			81,263,712			$	814			$	1,137,546				(3,154,032	)		$	(143,362	)		$	50,351			$	136,027			$	602,467			$	1,783,843

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

(Unaudited)

		Nine Months Ended
		September 30,
		2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	116,983			$	(38,023	)
Income from discontinued operations			59,769				20,181
Income (loss) from continuing operations			57,214				(58,204	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			147,427				129,539
Amortization of deferred finance costs			9,439				5,925
Non-cash loss (gain) on derivative value, net			55,229				(45,872	)
Non-cash compensation expense (benefit)			6,662				(4,132	)
Gain on asset sales and dispositions			(105,442	)			(32	)
Distributions paid to non-controlling interests			(43,799	)			(177,934	)
Equity loss in unconsolidated companies			2,903				688
Equity income in joint venture			(2,140	)			—
Distributions received from joint venture			1,657				—
Deferred income taxes			1,185				15,621
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other			22,816				(3,817	)
Accounts payable and accrued liabilities			(43,322	)			(40,621	)
Accounts payable and accounts receivable — affiliate			111				47
Other operating assets/liabilities			(161	)			29
Net cash provided by (used in) continuing operations operating activities			109,779				(178,763	)
Net cash provided by discontinued operations operating activities			14,209				36,626
Net cash provided by (used in) operating activities			123,988				(142,137	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(268,395	)			(448,738	)
Acquisition purchase price adjustment			—				31,429
Investment in Lightfoot Capital Partners, L.P.			(26	)			(437	)
Proceeds from asset sales			120,644				63
Other			(9,003	)			851
Net cash used in continuing operations investing activities			(156,780	)			(416,832	)
Net cash provided by (used in) discontinued operations investing activities			290,594				(22,626	)
Net cash provided by (used in) investing activities			133,814				(439,458	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities			744,000				908,000
Repayments under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities			(1,235,675	)			(1,110,025	)
Issuance of Atlas Energy Resources, LLC long-term debt			196,232				407,125
Issuance of Atlas Pipeline Partners, L.P. long-term debt			—				244,854
Repayments on Atlas Pipeline Partners, L.P. long-term debt			—				(122,847	)
Costs related to Atlas Energy, Inc. and Atlas Energy Resources, LLC Merger			(10,571	)			—
Net proceeds from Atlas Energy Resources equity offering			—				82,514
Net proceeds from Atlas Pipeline Partners, L.P. equity offering			16,142				206,901

		Nine Months Ended
		September 30,
		2009				2008
Dividends paid			(1,968	)			(4,701	)
APL Class A preferred unit redemption			(15,000	)			—
Purchase of treasury stock			(2,643	)			(34,861	)
Deferred financing costs and other			(17,122	)			(16,030	)
Net cash provided by (used in) financing activities			(326,605	)			560,930
Net change in cash and cash equivalents			(68,803	)			(20,665	)
Cash and cash equivalents, beginning of period			104,496				145,896
Cash and cash equivalents, end of period		$	35,693			$	125,231

See accompanying notes to consolidated financial statements

ATLAS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Atlas Energy, Inc. (the “Company”) is a publicly traded Delaware corporation (NASDAQ:ATLS) which is an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, the Michigan Basin, and the Illinois Basin. On September 29, 2009, the Company completed its merger with Atlas Energy Resources, LLC (“ATN”), the Company’s formerly publicly traded subsidiary and a Delaware limited liability company (NYSE: ATN), pursuant to the definitive merger agreement previously executed between the Company and ATN, with ATN surviving as the Company’s wholly-owned subsidiary (the “Merger”) (see Note 3). Additionally, Atlas America, Inc. changed its name to Atlas Energy, Inc. upon completion of the Merger.

In addition to its natural gas development and production operations, the Company also maintains ownership interests in the following entities:

•

Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. At September 30, 2009, the Company had a 2.2% direct ownership interest in APL;

•

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL. Through the Company’s ownership of AHD’s general partner, it manages AHD. AHD’s cash generating assets currently consist solely of its interests in APL. At September 30, 2009, the Company owned approximately 64.4% of the outstanding common units of AHD. AHD owned a 2% general partner interest, all of the incentive distribution rights, an approximate 11.2% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units in APL; and

•

Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC, (“Lightfoot GP”), the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. The Company has an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $20.0 million in Lightfoot LP. The Company also has direct and indirect ownership interest in Lightfoot LP. As of September 30, 2009, the Company has invested $10.7 million in Lightfoot LP.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2008 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 for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has evaluated subsequent events through November 9, 2009, the date the financial statements were issued. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. Certain amounts in the prior year’s consolidated financial statements have also been reclassified to conform to the current year presentation, including $18.8 million of pre-development costs shown as component of “Property, plant, and equipment, net” which was previously combined with

“Liabilities associated with drilling contracts” on the Company’s consolidated balance sheets at December 31, 2008. On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (see Note 5). As such, the Company has adjusted its prior period consolidated financial statements and related footnote disclosures presented within this Form 10-Q to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations. The Company’s consolidated financial statements and related footnotes as of and for the year ended December 31, 2008 contained within its Annual Report on Form 10-K have been restated to reflect the amounts related to the discontinued operations of the NOARK system (see Note 5) and Financial Accounting Standards Board issued Accounting Standard Concept 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” (see Note 2).The results of operations for the three and nine month periods ended September 30, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Company’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2008.

Principles of Consolidation and Non-controlling Interest

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned at September 30, 2009 except for AHD, which is controlled by the Company, and APL, which is controlled by AHD. The financial statements of AHD include its accounts and the accounts of its subsidiaries, all of which are wholly-owned except for APL. Prior to ATN’s merger with the Company’s wholly-owned subsidiary on September 29, 2009, ATN was a controlled subsidiary of the Company but was not wholly-owned (see Note 3). The non-controlling ownership interests in the net income (loss) of ATN prior to the Merger, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations. The non-controlling interests in the assets and liabilities of AHD and APL are reflected as a component of stockholders’ equity on the Company’s consolidated balance sheets. The non-controlling interests in the assets and liabilities of ATN are reflected as a component of stockholders’ equity on the Company’s December 31, 2008 consolidated balance sheet. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Company’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Company has an interest (“the Partnerships”). Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties” below.

The Company’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Company reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Company also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests as a component of stockholders’ equity on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which is reflected within non-controlling interests on the Company’s consolidated balance sheets.

The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Due to the Midkiff/Benedum system’s status as an undivided joint venture, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system. On November 2, 2009, APL’s agreement with Pioneer, whereby Pioneer had an option to purchase additional interest in the Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 19.)

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, deferred tax assets and liabilities, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. 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 month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2009 represent actual results in all material respects (see “- Revenue Recognition” accounting policy for further description).

Impairment of Long-Lived Assets

The Company 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 Company’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 Company’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 Company 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 particular, the Company’s reserve estimates for its investment in the Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Company’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

Partnership management, operating contracts and non-compete agreement. The Company has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. In addition, the Company entered into a two-year non-compete agreement in connection with the acquisition of its Michigan operations. The Company amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at September 30, 2009 and December 31, 2008 (in thousands):

										Estimated
		September 30,				December 31,				Useful Lives
		2009				2008				In Years
Gross Carrying Amount:
Customer contracts and relationships		$	235,382			$	235,382				7 - 20
Partnership management and operating contracts			14,343				14,343				2 - 13
Non-compete agreement			890				890
		$	250,615			$	250,615
Accumulated Amortization:
Customer contracts and relationships		$	(60,902	)		$	(41,735	)
Partnership management and operating contracts			(11,284	)			(10,728	)
Non-compete agreement			(890	)			(667	)
		$	(73,076	)		$	(53,130	)
Net Carrying Amount:
Customer contracts and relationships		$	174,480			$	193,647
Partnership management and operating contracts			3,059				3,615
Non-compete agreement			—				223
		$	177,539			$	197,485

Amortization expense on intangible assets was $6.6 million and $6.7 million for the three months ended September 30, 2009 and 2008, respectively, and $19.9 million and $20.1 million for the nine months ended September 30, 2009 and 2008, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; 2013-$24.6 million; and 2014-$20.6 million.

Goodwill

At September 30, 2009 and December 31, 2008, the Company had $35.2 million of goodwill recorded in connection with consummated acquisitions. The changes in the carrying amount of goodwill for the nine months ended September 30, 2009 and 2008 were as follows (in thousands):

		Nine Months Ended
		September 30,
		2009				2008
Balance, beginning of period		$	35,166			$	744,449
APL post-closing purchase price adjustment with seller and purchase price allocation adjustment — Chaney Dell and Midkiff/Benedum systems acquisition			—				(2,217	)
APL recovery of state sales tax initially paid on transaction — Chaney Dell and Midkiff/Benedum systems acquisition			—				(30,206	)
Balance, end of period		$	35,166			$	712,026

As a result of its impairment evaluation at December 31, 2008, the Company recognized a $676.9 million non-cash impairment charge within its consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of its reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of its reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions. There were no goodwill impairments recognized by the Company related to ATN during the year ended December 31, 2008 and for the period ended September 30, 2009.

The Company tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, the Company’s management must apply judgment in determining the estimated fair value of these reporting units. The Company’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Company’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Company also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Company’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in management’s judgment. The Company will continue to evaluate goodwill at least annually or when impairment indicators arise. During the nine months ended September 30, 2009, no impairment indicators arose.

In April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition at March 31, 2008.

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common stock outstanding during the period. Diluted net income (loss) per share is calculated by dividing net income (loss) by the sum of the weighted average number of common stock outstanding and the dilutive effect of potential shares issuable during the period, as calculated by the treasury stock method. Dilutive potential shares of common stock consist of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such shares that could have been reacquired (at the weighted average market price of shares during the period) with the proceeds received from the exercise of the stock options (see Note 17). The following table sets forth the reconciliation of the Company’s weighted average number of common shares used to compute basic net income (loss) per share with those used to compute diluted net income (loss) per share (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008(1)				2009				2008(1)
Weighted average number of shares — basic			39,780				40,093				39,460				40,251
Add: effect of dilutive incentive awards			—				1,901				591				1,870
Weighted average number of common shares — diluted			39,780				41,994				40,051				42,121

Revenue Recognition

Certain energy activities are conducted by the Company through, and a portion of its revenues are attributable to, sponsored investment Partnerships. The Company contracts with the Partnerships to drill partnership wells. The contracts require that the Partnerships must pay the Company the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 180 days. On an uncompleted contract, the Company classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s consolidated balance sheets. The Company recognizes well services revenues at the time the services are performed. The Company is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues.

The Company 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 Company has an interest with other producers are recognized on the basis of the Company’s percentage ownership of working interest and/or overriding royalty. Generally, the Company’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.

Atlas Pipeline. APL’s revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

•

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

•

POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

•

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “-Use of Estimates” accounting policy for further description). The Company had unbilled revenues at September 30, 2009 and December 31, 2008 of $66.3 million and $87.4 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net 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, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income (loss)” and for the Company includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges and post-retirement plan liabilities (which are presented net of income taxes). The following table sets forth the calculation of the Company’s comprehensive income (loss) (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Net income (loss)		$	(9,886	)		$	218,157			$	116,983			$	(38,023	)
(Income) loss attributable to non-controlling interests			9,172				(194,054	)			(103,686	)			60,777
Net income (loss) attributable to common shareholders			(714	)			24,103				13,297				22,754
Other comprehensive loss:
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of (tax) benefit of ($26,351) and ($53,885) for the three months ended September 30, 2009 and 2008, respectively, and ($39,354) and $9,431 for the six months ended September 30, 2009 and 2008, respectively			(14,761	)			242,645				45,634				(111,397	)
Less: reclassification adjustment for realized losses (gains) in net income (loss), net of (tax) benefit of $13,027 and ($5,633) for the three months ended September 30, 2009 and 2008, respectively, and $20,722 and ($6,810) for the nine months ended September 30, 2009 and 2008, respectively			(14,050	)			30,502				(30,722	)			63,398
Changes in non-controlling interest related to items in other comprehensive income (loss)			49,653				(180,054	)			14,231				44,256
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of (tax) benefit of $13 and $51 for the three months ended September 30, 2009 and 2008, respectively, and $39 and $153 for the nine months ended September 30, 2009 and 2008, respectively			22				87				65				296
Total other comprehensive (loss) gain			20,864				93,180				29,208				(3,447	)
Comprehensive income (loss) attributable to common shareholders		$	20,150			$	117,283			$	42,505			$	19,307

Recently Adopted Accounting Standards

In August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 amends Subtopic 820-10, “Fair Value Measurements and Disclosures — Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Company adopted the requirements on September 30, 2009 and it did not have a material impact on its financial position, results of operations or related disclosures.

In August 2009, the FASB issued Accounting Standards Update 2009-04, “Accounting for Redeemable Equity Instruments — Amendment to Section 480-10-S99” (“Update 2009-04”). Update 2009-04 updates Section 480-10-S99, “Distinguishing Liabilities from Equity”, to reflect the SEC staff’s views regarding the application of Accounting Series Release No. 268, “Presentation in Financial Statements of ‘Redeemable Preferred Stocks’” (“ASR No. 268”). ASR No. 268 requires preferred securities that are redeemable for cash or other assets to be classified outside of permanent equity if they are redeemable (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder, or (3) upon the occurrence of an event that is not solely within the control of the issuer. The Company adopted the requirements of FASB Update 2009-04 on August 1, 2009 and it did not have a material impact on its financial position, results of operations or related disclosures.

In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 — Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. All required references to non-SEC accounting standards have been modified by the Company. The Company adopted the requirements of Update 2009-01 to its financial statements on September 30, 2009 and it did not have a material impact to the Company’s financial statement disclosures.

In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions require management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Company adopted the requirements of this standard on June 30, 2009 and it did not have a material impact to its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Company’s current practices with respect to evaluating, recording and disclosing subsequent events.

In April 2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of ASC 820-10-65-4 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued ASC 320-10-65-1, “Recognition and Presentation of Other-Than-Temporary Impairments” (“ASC 320-10-65-1”), which changes previously existing guidance for determining whether an impairment is other than temporary for debt securities. ASC 320-10-65-1 replaces the previously existing requirement that an entity’s management assess if it has both the intent and ability to hold an impaired security until recovery with a requirement that management assess that it does not have the intent to sell the security and that it is more likely than not that it will not have to sell the security before recovery of its cost basis. ASC 320-10-65-1 also requires that an entity recognize noncredit losses on held-to-maturity debt securities in other comprehensive income and amortize that amount over the remaining life of the security and for the entity to present the total other-than-temporary impairment in the statement of operations with an offset for the amount recognized in other comprehensive income. ASC 320-10-65-1 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted these requirements on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825-10-65-1”), which requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted these requirements on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued ASC 805-20-30-23, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“ASC 805-20-30-23”), which requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability would generally be recognized in accordance with previous requirements. ASC 805-20-30-23 eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. ASC 805-20-30-23 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company). The Company adopted the requirements on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

 

18

In June 2008, the FASB issued ASC 260-10-45-61A, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“ASC 260-10-45-61A”). ASC 260-10-45-61A applies to the calculation of earnings per share (“EPS”) described in previous guidance, for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. ASC 260-10-45-61A is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. The Company adopted the requirements on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2008, the FASB issued ASC 350-30-65-1, “Determination of Useful Life of Intangible Assets” (“ASC 350-30-65-1”). ASC 350-30-65-1 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previous guidance. The intent of ASC 350-30-65-1 is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. The Company adopted the requirements of ASC 350-30-65-1 on January 1, 2009 and its adoption did not have a material impact on its financial position and results of operations.

In March 2008, the FASB issued ASC 260-10-55-103 through 55-110, “Application of the Two-Class Method” (“ASC 260-10-55-103”), which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. ASC 260-10-55-103 considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. The Company’s adoption of ASC 260-10-55-103 on January 1, 2009 impacted its presentation of net income (loss) per common limited partner unit as the Company previously presented net income (loss) per common limited partner unit as though all earnings were distributed each quarterly period (see “—Net Income (Loss) Per Common Unit”). The Company adopted the requirements of ASC 260-10-55-103 on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In March 2008, the FASB issued ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Company adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (see Note 10).

In December 2007, the FASB issued ASC 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” (“ASC 810-10-65-1”). ASC 810-10-65-1 establishes accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported and disclosed on the face of the consolidated statement of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, ASC 810-10-65-1 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. The Company adopted the requirements of ASC 810-10-65-1on January 1, 2009 and adjusted its presentation of its financial position and results of operations. Prior period financial position and results of operations have been adjusted retrospectively to conform to these provisions.

In December 2007, the FASB issued ASC 805, “Business Combinations” (“ASC 805”). ASC 805 retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. ASC 805 requires an acquirer to recognize the assets acquired, liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Additionally, it requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the non-controlling interests in the acquiree, at the full amounts of their fair values. The Company adopted these requirements on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

Recently Issued Accounting Standards

In October 2009, the FASB issued Accounting Standards Update 2009-15, “Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing” (“Update 2009-15”). Update 2009-15 includes amendments to Topic 470, “Debt”, and Topic 260, “Earnings per Share”, to provide guidance on share-lending arrangements entered into on an entity’s own shares in contemplation of a convertible debt offering or other financing. These requirements are effective for existing arrangements for fiscal years beginning on or after December 15, 2009, and interim periods within those fiscal years for arrangements outstanding as of the beginning of those years, with retrospective application required for such arrangements that meet the criteria. These requirements are also effective for arrangements entered into on (not outstanding) or after the beginning of the first reporting period that begins on or after June 15, 2009. The Company will apply these requirements upon its adoption on January 1, 2010 and does not expect it to have a material impact to its financial position or results of operations or related disclosures.

In June 2009, the FASB issued ASC 810-10-25-20 through 25-59, “Consolidation of Variable Interest Entities” (“ASC 810-10-25-20”), which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. ASC 820-10-25-20 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. These requirements are effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the impact of these requirements upon its adoption on January 1, 2010.

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission (“SEC”) announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

•

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

	•		Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.
	•		Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.
	•		Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”.
	•		Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
	•		Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Company will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company is currently in the process of evaluating the new requirements.

NOTE 3 — COMMON STOCK

Merger with Atlas Energy Resources, LLC

On September 29, 2009, the Company completed its merger with ATN pursuant to the definitive merger agreement previously executed between the Company and ATN, with ATN surviving as the Company’s wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by the Company were exchanged for 38.8 million shares of the Company’s common stock (a ratio of 1.16 shares of the Company’s common stock for each Class B common unit of ATN). The Company also changed its name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of the Board of Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which creates a new stock incentive plan for the combined entity. The Company also has the legacy Atlas America stock incentive plan and the legacy ATN Long-Term Incentive Plan (see Note 17).

Due to the Merger, the Company recognized a reduction of $556.4 million in non-controlling interest and a decrease to deferred tax liability of $179.4 million, all of which was reflected as an increase to additional paid-in-capital on the Company’s consolidated balance sheets.

The Company also recognized the fair value of the interests exchanged in the Merger, excluding transaction costs incurred, of $724.8 million as a non-cash item in its consolidated statement of cash flows for the nine months ended September 30, 2009.

Authorized Shares

On July 13, 2009, the Company’s stockholders approved an increase to its authorized shares from 49,000,000 authorized shares to 114,000,000 authorized shares.

Stock Repurchase Plan

In September 2008, the Company’s Board of Directors approved a stock repurchase program of up to $50.0 million at a price not to exceed $36.00 per share. The daily repurchase amount was limited to 50,000 shares. The Company purchased 595,292 of its shares during September and October 2008 for a total price of $20.0 million under this program. In addition, the Company utilized the remaining $20.0 million of availability under a stock repurchase program approved in September 2005 to purchase 560,291 shares in August and September 2008. The average price for the shares purchased during 2008 was $34.76 per share.

Stock Splits

On April 22, 2008, the Company’s Board of Directors approved a three-for-two stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 30, 2008. Information pertaining to shares and earnings per share has been restated for the three and nine months ended September 30, 2008 in the accompanying consolidated financial statements and notes to the consolidated financial statements to reflect this split.

The following data presents pro forma revenue, net income, net income per share and basic and diluted weighted average shares outstanding for the Company for the three and nine months ended September 30, 2009 and 2008, respectively, as if the Merger discussed above had occurred on January 1, 2008. The Company has prepared these unaudited pro forma financial results for comparative purposes only. The pro forma adjustments reflect an adjustment to income previously allocated to non-controlling interest offset by the restated tax impact. These pro forma financial results may not be indicative of the results that would have occurred if the Merger had been completed at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per share data; unaudited):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Revenue		$	367,184			$	771,002			$	1,145,264			$	1,583,473
Income attributable to common shareholders:
Income from continuing operations		$	562			$	36,495			$	18,591			$	59,568
Discontinued operations			—				433				4,253				1,323
Net income attributable to common shareholders		$	562			$	36,928			$	22,844			$	60,891
Net income attributable to common shareholders per share — basic:
Income from continuing operations attributable to common shareholders		$	0.01			$	0.46			$	0.24			$	0.75
Discontinued operations attributable to common shareholders			0.00				0.01				0.05				0.02
Net income attributable to common shareholders		$	0.01			$	0.47			$	0.29			$	0.77
Net income attributable to common shareholders per share — diluted:
Income from continuing operations attributable to common shareholders		$	0.01			$	0.44			$	0.24			$	0.73
Discontinued operations attributable to common shareholders			0.00				0.01				0.05				0.02
Net income attributable to common shareholders		$	0.01			$	0.45			$	0.29			$	0.75
Weighted average common shares outstanding:
Basic			78,136				78,869				78,095				79,027
Diluted			79,144				81,307				78,714				81,451

NOTE 4 — APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which owns and operates APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. Williams contributed cash of $100.0 million to the joint venture (of which APL received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. In addition, ATN sold certain assets to the joint venture for $12.0 million. APL contributed its Appalachia Basin natural gas gathering system and retained a 49% ownership interest. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on the Company’s consolidated balance sheet at fair value and recognized a gain on sale of $108.9 million, including $54.2 million associated with the re-measurement of APL’s investment in Laurel Mountain to fair value. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 9). In addition, the Company sold two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania to Laurel Mountain for $10.0 million, resulting in a $5.7 million loss which is included in gain on asset sale on the Company’s consolidated statement of operations. Upon the completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with the Company which superseded the existing natural gas gathering agreements and omnibus agreement between APL and the Company. Under the new gas gathering agreement, the Company is obligated to pay the joint venture all of the gathering fees it collects from its investment drilling partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the Company’s investment drilling partnerships’ gas). APL has accounted for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain other income (loss) on the Company’s consolidated statements of operations.

The following table provides summarized statement of operations and balance sheet data on a 100% basis for Laurel Mountain for the three and nine months ended September 30, 2009 and as of September 30, 2009 (in thousands):

		Three Months				Nine Months
		Ended				Ended
		September 30, 2009				September 30, 2009(1)
Statement of Operations data:
Total revenue		$	9,622			$	12,690
Net income			2,386				3,664

		September 30, 2009
Balance Sheet data:
Current assets		$	9,871
Long-term assets			245,577
Current liabilities			19,303
Long-term liabilities			8,500
Net equity			227,645

NOTE 5 — DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 9). The Company accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $48.8 million (net of income taxes of $2.2 million) on the sale of APL’s NOARK assets within income from discontinued operations on its consolidated financial statement of operations for the three and nine months ended September 30, 2009. The following table summarizes the components included within income from discontinued operations on the Company’s consolidated statements of operations (amounts in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Total revenues		$	—			$	13,468			$	21,274			$	45,827
Total costs and expenses			—				(6,930	)			(9,858	)			(24,798	)
Income before income tax expense			—				6,538				11,416				21,029
Income tax expense			—				(277	)			(498	)			(848	)
Income from discontinued operations		$	—			$	6,261			$	10,918			$	20,181

The following table summarizes the components included within total assets and liabilities of discontinued operations within the Company’s consolidated balance sheet for the period indicated (amounts in thousands):

		December 31,
		2008
Cash and cash equivalents		$	75
Accounts receivable			12,365
Prepaid expenses and other			1,001
Total current assets of discontinued operations			13,441
Property, plant and equipment, net			241,926
Other assets, net			239
Total assets of discontinued operations		$	255,606
Accounts payable		$	4,120
Accrued liabilities			5,892
Accrued producer liabilities			560
Total current liabilities of discontinued operations		$	10,572

NOTE 6 — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the unit-of-production or straight-line methods over the asset’s estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The following is a summary of property, plant and equipment (in thousands):

										Estimated
		September 30,				December 31,				Useful Lives
		2009				2008(1)				in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests		$	1,237,331			$	1,214,991
Pre-development costs			14,750				18,772
Wells and related equipment			970,063				872,128
Total proved properties			2,222,144				2,105,891
Unproved properties			43,279				43,749
Support equipment			8,605				9,527
Total natural gas and oil properties			2,274,028				2,159,167
Pipelines, processing and compression facilities			1,671,863				1,728,472				15 - 40
Rights of way			166,874				168,206				20 - 40
Land, buildings and improvements			24,593				24,385				10 - 40
Other			21,867				22,108				3 - 10
			4,159,225				4,102,338
Less — accumulated depreciation, depletion and amortization			(450,836	)			(357,523	)
		$	3,708,389			$	3,744,815

The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs and delay rentals are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one barrel equals 6 thousand cubic feet (“Mcf”). Depletion is provided on the units-of-production method.

Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method. Depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Company’s costs of property interests in uncontrolled, but proportionately consolidated from investment partnerships, wells drilled solely by the Company for its interest, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statements of income. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

 

The estimated liability is based on the Company’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 Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

A reconciliation of the Company’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Asset retirement obligations, beginning of period		$	50,142			$	45,334			$	48,136			$	42,358
Liabilities incurred			125				975				721				2,615
Liabilities settled			(113	)			(36	)			(198	)			(38	)
Accretion expense			753				687				2,248				2,025
Asset retirement obligations, end of period		$	50,907			$	46,960			$	50,907			$	46,960

The accretion expense is included in depreciation, depletion and amortization in the Company’s consolidated statements of operations.

NOTE 9 — DEBT

As of September 30, 2009, the Company’s debt consists entirely of instruments entered into by ATN, AHD and APL. The Company has not guaranteed any of its subsidiaries’ debt obligations, with the exception of the AHD credit facility. Total debt consists of the following (in thousands):

		September 30,				December 31,
		2009				2008
ATN revolving credit facility		$	270,000			$	467,000
ATN 10.75% senior notes — due 2018			406,105				406,655
ATN 12.125% senior notes — due 2017			196,350				—
AHD credit facility			12,000				46,000
APL revolving credit facility			315,000				302,000
APL term loan			433,505				707,180
APL 8.125% senior notes — due 2015			271,495				261,197
APL 8.75% senior notes — due 2018			223,050				223,050
Total debt			2,127,505				2,413,082
Less current maturities			(12,000	)			—
Total long-term debt		$	2,115,505			$	2,413,082

ATN Revolving Credit Facility

At September 30, 2009, ATN had a credit facility with a syndicate of banks with a borrowing base of $600.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in oil and gas reserves or is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by ATN. On July 13, 2009, ATN issued $200.0 million of senior unsecured notes, and the borrowing base was reduced by $50.0 million to $600.0 million. Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at September 30, 2009, which was not reflected as borrowings on the Company’s consolidated balance sheets. The facility is secured by substantially all of ATN’s assets and is guaranteed by each of its subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at ATN’s option. On April 9, 2009, the credit agreement was amended to, among other things, increase the applicable margin on Eurodollar Loans from a range of 100 to 175 basis points to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points. At September 30, 2009 and December 31, 2008, the weighted average interest rate on outstanding borrowings was 2.7% and 2.8%, respectively. The base rate for any day equals the higher of the federal funds rate plus 0.50%, the J.P. Morgan prime rate or the adjusted LIBOR for a month interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities.

On July 10, 2009, ATN’s credit agreement was amended to, among other things, permit the Merger to allow ATN to distribute (a) amounts equal to the Company’s income tax liability attributable to ATN’s net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, it may carry over up to $20.0 million for use in the next year.

The events which constitute an event of default for ATN’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against ATN in excess of a specified amount and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. ATN is in compliance with these covenants as of September 30, 2009. The credit facility also requires ATN to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 3.75 to 1.0 commencing January 1, 2009, decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter. According to the definitions contained in ATN’s credit facility, ATN’s ratio of current assets to current liabilities was 2.1 to 1.0 and its ratio of total debt to EBITDA was 3.0 to 1.0 at September 30, 2009.

ATN Senior Notes

At September 30, 2009, ATN had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“ATN 10.75% Senior Notes”) due on February 1, 2018 and $200.0 million principal amount outstanding of 12.125% senior unsecured notes due August 1, 2017 (“ATN 12.125% Senior Notes”; collectively, the “ATN Senior Notes”). The ATN 12.125% Senior Notes were issued on July 13, 2009 in a public offering at a price of 98.116% to par value for a yield 12.5% at maturity. Net proceeds from the offering were used to reduce outstanding borrowings under ATN’s revolving credit facility. Interest on the ATN Senior Notes in the aggregate is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 10.75% Senior Notes are redeemable at any time on or after February 1, 2013, and the ATN 12.125% Senior Notes are redeemable at any time on or after August 1, 2013, at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011 for the ATN 10.75% Notes and before August 1, 2012 for the ATN 12.125% Senior Notes, ATN may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price. The ATN Senior Notes are also subject to repurchase by ATN at a price equal to 101% for the ATN 10.75% Senior Notes and ATN 12.125% Senior Notes of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if ATN does not reinvest the net proceeds within 360 days. The ATN Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under its credit facility. The indentures governing the ATN Senior Notes contain covenants, including limitations of ATN’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. ATN is in compliance with these covenants as of September 30, 2009.

AHD Credit Facility

At September 30, 2009, AHD had $12.0 million outstanding under a revolving credit facility with a syndicate of banks. On June 1, 2009, AHD entered into an amendment to its credit facility agreement which, among other changes:

	•		required AHD to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility, $15.0 million of which was borrowed from the Company through a subordinate loan;
	•		required AHD to repay $4.0 million of the then-remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. AHD repaid $4.0 million of its outstanding credit facility borrowings on July 13, 2009 and October 13, 2009 in accordance with the amendment through a subordinate loan with the Company. AHD may not borrow additional amounts under the credit facility or issue letters of credit;
	•		requires AHD to use any of its “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires AHD to repay borrowings under the credit facility with the net proceeds of any sales of its common units in APL;
	•		eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL and the interest coverage ratio (all as defined within the credit facility agreement);
	•		prohibits AHD from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits AHD to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and
	•		reduced the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rate on the outstanding credit facility borrowings at September 30, 2009 was 3.25%.

Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding APL and its subsidiaries). AHD’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; or enter into a merger or sale of substantially all of AHD’s property or assets, including the sale or transfer of interest in its subsidiaries. AHD is in compliance with these covenants as of September 30, 2009. The events which constitute an event of default under AHD’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against AHD in excess of a specified amount, a change of control of the Company, AHD’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.

AHD’s $30 million repayment was funded from the proceeds of (i) a loan from the Company in the amount of $15 million (obtained on June 1, 2009) and (ii) the purchase by APL of $15 million of preferred equity in a newly-formed subsidiary of AHD. Under the subordinate loan, interest accrues quarterly on the outstanding principal amount at the rate of 12% per annum, but before the maturity date, interest is payable entirely by increasing the principal amount of the note, and the maturity date is generally the day following the day that AHD pays all indebtedness under the credit facility (“Termination Date”). The material terms of the preferred units purchased by APL in a newly-formed subsidiary of AHD are as follows: distributions are payable quarterly at the rate of 12% per annum, but before the Termination Date, distributions will be paid by increasing APL’s investment in the preferred units; upon the Termination Date, all preferred distributions will be paid in cash to APL; and AHD has the option, after the Termination Date, of redeeming all of the preferred units APL owns for an amount equal to the preferred unit capital.

On June 1, 2009, in connection with AHD’s amendment of the credit facility, the Company guaranteed the then remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, AHD issued to the Company a promissory note which requires it to pay interest to the Company in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that AHD repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.

APL Term Loan and Revolving Credit Facility

At September 30, 2009, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at September 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at September 30, 2009 was 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $9.1 million was outstanding at September 30, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet.

On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:

	•		increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;
	•		for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;
	•		increased the maximum ratio of total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and decreased the ratio of interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain;

	•		instituted a maximum ratio of senior secured funded debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain;
	•		required that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as defined in the credit agreement) of at least $50.0 million;
	•		generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;
	•		permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and
	•		instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio.

In June 2008, APL entered into an amendment to the credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 10) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes. Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.

Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and the Laurel Mountain joint venture, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of September 30, 2009.

The events which constitute an event of default for the credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s General Partner. The credit facility requires APL to maintain the following ratios:

Maximum

Minimum

Maximum

Senior Secured

Interest

Leverage

Leverage

Coverage

Fiscal quarter ending:

Ratio

Ratio

Ratio

September 30, 2009

6.50x

3.75x

2.50x

December 31, 2009

8.50x

5.25x

1.70x

March 31, 2010

9.25x

5.75x

1.40x

June 30, 2010

8.00x

5.00x

1.65x

September 30, 2010

7.00x

4.25x

1.90x

December 31, 2010

6.00x

3.75x

2.20x

Thereafter

5.00x

3.00x

2.75x

As of September 30, 2009, APL’s leverage ratio was 4.2 to 1.0, its senior secured leverage ratio was 2.5 to 1.0 and its interest coverage ratio was 3.3 to 1.0.

APL Senior Notes

At September 30, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $4.0 million of unamortized discount as of September 30, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the APL 8.125% Senior Notes are redeemable at any time after December 15, 2010 at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL 8.75% Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units. Management of APL estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on the Company’s consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense within the Company’s consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of September 30, 2009.

NOTE 10 — DERIVATIVE INSTRUMENTS

The Company, AHD and APL use a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price and interest rate risk management activities. The Company and its subsidiaries enter into financial instruments to hedge its forecasted natural gas, NGLs, crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Its subsidiaries also enter into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs, crude oil and condensate is sold or interest payments on the underlying debt instrument is due. Under swap agreements, the Company and its subsidiaries receives or pays a fixed price and receives or remits 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, NGLs, crude oil and condensate at a fixed price for the relevant contract period.

The Company and its subsidiaries formally document 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 and interest derivative contracts to the forecasted transactions. The Company and its subsidiaries assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined 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 Company and its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company and its subsidiaries through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. For derivatives qualifying as hedges, the Company and its subsidiaries recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for the Company’s derivatives and gathering, transmission and processing revenues for APL derivatives, and the portion relating to interest rate derivatives to interest expense within the Company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company and its subsidiaries recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated statements of operations as they occur.

Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected net derivative assets on its consolidated balance sheets of $50.9 million and $89.3 million at September 30, 2009 and December 31, 2008, respectively. Of the $50.4 million of net gain in accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet at September 30, 2009, if the fair values of the instruments remain at current market values, the Company will reclassify $32.9 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $37.1 million of gains to gas and oil production revenues, $2.2 million of losses to gathering, transmission and processing revenues and $2.1 million of losses to interest expense. Aggregate gains of $17.6 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $20.3 million of gains to gas and oil production revenues, $1.5 million of losses to gathering, transmission and processing revenues and $1.1 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Company’s derivative instruments as of September 30, 2009 and December 31, 2008, as well as the gain or loss recognized in income for effective derivative instruments for the nine months ended September 30, 2009 and 2008. There were no gains or losses recognized in income for ineffective derivative instruments for the nine months ended September 30, 2009 and 2008.

Fair Value of Derivative Instruments:

		Asset Derivatives										Liability Derivatives
Derivatives in				Fair Value										Fair Value
Cash Flow		Balance Sheet		September 30,				December 31,				Balance Sheet		September 30,				December 31,
Hedging Relationships		Location		2009				2008				Location		2009				2008
				(in thousands)										(in thousands)
Commodity contracts:		Current assets		$	84,446			$	107,766			Current liabilities		$	(1,273	)		$	(9,348	)
		Long-term assets			40,425				69,451			Long-term liabilities			(23,725	)			(8,410	)
					124,871				177,217						(24,998	)			(17,758	)
Interest rate contracts:		Current assets			—				—			Current liabilities			(3,832	)			(3,481	)
		Long-term assets			—				—			Long-term liabilities			(866	)			(2,361	)
					—				—						(4,698	)			(5,842	)
Total derivatives				$	124,871			$	177,217					$	(29,696	)		$	(23,600	)