Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended September 30, 2009

OR

 

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

For the transition period from              to             

Commission file number: 1-14998

 

 

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

DELAWARE		23-3011077
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1550 Coraopolis Heights Road Moon Township, Pennsylvania		15108
(Address of principal executive office)		(Zip code)

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

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in rule 12b-2 of the Exchange Act.

 

Large accelerated filer		x		Accelerated filer		¨
Non-accelerated filer		¨  (Do not check if a smaller reporting company)		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  ¨    No  x

The number of common units of the registrant outstanding on November 4, 2009 was 50,504,978.

 

 

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

 

				PAGE
PART I. FINANCIAL INFORMATION				3
Item 1.		Financial Statements (Unaudited)		3
		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 Partners’ Capital 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		8
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		46
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		65
Item 4.		Controls and Procedures		72
PART II. OTHER INFORMATION				72
Item 1A.		Risk Factors		72
Item 6.		Exhibits		72
SIGNATURES				75

 

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PART I. FINANCIAL INFORMATION

 

ITEM 1.

FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

		September 30, 2009				December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents		$	5,261			$	1,445
Accounts receivable – affiliates			—				537
Accounts receivable			71,118				100,000
Current portion of derivative asset			4,514				44,961
Prepaid expenses and other			15,304				10,996
Current assets of discontinued operations			—				13,441
Total current assets			96,197				171,380
Property, plant and equipment, net			1,698,226				1,781,011
Intangible assets, net			174,480				193,647
Investment in joint venture			133,740				—
Long-term portion of derivative asset			1,980				—
Other assets, net			34,938				24,993
Long-term assets of discontinued operations			—				242,165
		$	2,139,561			$	2,413,196
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable – affiliates		$	798			$	—
Accounts payable			19,706				66,571
Accrued liabilities			31,411				15,809
Current portion of derivative liability			41,019				60,396
Accrued producer liabilities			45,539				66,846
Current liabilities of discontinued operations			—				10,572
Total current liabilities			138,473				220,194
Long-term portion of derivative liability			9,256				48,159
Long-term debt, less current portion			1,243,050				1,493,427
Other long-term liability			448				574
Commitments and contingencies
Partners’ capital:
Class A preferred limited partner’s interest			—				27,853
Class B preferred limited partner’s interest			14,955				10,007
Common limited partners’ interests			823,195				735,742
Investment in Class B cumulative preferred member units of Atlas Pipeline Holdings II, LLC (reported as treasury units)			(15,000	)			—
General partner’s interest			16,581				14,521
Accumulated other comprehensive loss			(61,142	)			(104,944	)
			778,589				683,179
Non-controlling interest			(30,255	)			(32,337	)
Total partners’ capital			748,334				650,842
		$	2,139,561			$	2,413,196

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Revenue:
Natural gas and liquids		$	194,440			$	396,739			$	526,478			$	1,186,688
Transportation, compression and other fees – affiliates			380				11,916				16,877				32,496
Transportation, compression and other fees – third parties			4,719				6,125				12,574				16,792
Equity income in joint venture			1,430				—				2,140				—
Gain on asset sales			1,499				—				111,440				—
Other income (loss), net			4,065				153,878				(6,431	)			(247,136	)
Total revenue and other income (loss), net			206,533				568,658				663,078				988,840
Costs and expenses:
Natural gas and liquids			144,990				314,315				409,411				937,852
Plant operating			14,762				16,652				42,713				46,418
Transportation and compression			134				2,883				6,256				7,842
General and administrative			8,379				(3,832	)			24,846				8,325
Compensation reimbursement – affiliates			375				1,175				1,125				3,694
Depreciation and amortization			21,896				20,741				67,563				61,200
Interest			28,320				22,098				75,820				62,663
Total costs and expenses			218,856				374,032				627,734				1,127,994
Income (loss) from continuing operations			(12,323	)			194,626				35,344				(139,154	)
Discontinued operations:
Gain on sale of discontinued operations			—				—				51,078				—
Income from discontinued operations			—				6,538				11,417				21,029
Income from discontinued operations			—				6,538				62,495				21,029
Net income (loss)			(12,323	)			201,164				97,839				(118,125	)
Income attributable to non-controlling interests			(954	)			(2,591	)			(2,075	)			(7,793	)
Preferred unit dividends			—				(650	)			(900	)			(1,437	)
Preferred unit imputed dividend cost			—				—				—				(505	)
Net income (loss) attributable to common limited partners and the general partner		$	(13,277	)		$	197,923			$	94,864			$	(127,860	)
Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partner interest:
Continuing operations		$	(13,011	)		$	179,466			$	31,718			$	(168,897	)
Discontinued operations			—				6,406				61,239				20,606
			(13,011	)			185,872				92,957				(148,291	)
General partner interest:
Continuing operations			(266	)			11,919				651				20,008
Discontinued operations			—				132				1,256				423
			(266	)			12,051				1,907				20,431

 

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Net income (loss) attributable to common limited partners and the general partner:
Continuing operations			(13,277	)			191,385			32,369			(148,889	)
Discontinued operations			—				6,538			62,495			21,029
		$	(13,277	)		$	197,923		$	94,864		$	(127,860	)
Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations		$	(0.26	)		$	3.89		$	0.67		$	(4.07	)
Discontinued operations			—				0.14			1.29			0.50
		$	(0.26	)		$	4.03		$	1.96		$	(3.57	)
Diluted:
Continuing operations		$	(0.26	)		$	3.79		$	0.67		$	(4.07	)
Discontinued operations Diluted			—				0.14			1.29			0.50
		$	(0.26	)		$	3.93		$	1.96		$	(3.57	)
Weighted average common limited partner units outstanding:
Basic			49,127				45,937			47,554			41,360
Diluted			49,127				47,203			47,591			41,360

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009

(in thousands, except unit data)

(Unaudited)

 

		Number of Limited Partner Units							Class A Preferred Limited Partner				Class B Preferred Limited Partner				Common Limited Partners				General Partner				Accumulated Other Comprehensive Income (Loss)				Class B Preferred Units of Atlas Pipeline Holdings II, LLC				Non-controlling Interests				Total Partners’ Capital
		Class A Preferred			Class B Preferred		Common
Balance at January 1, 2009		30,000			10,000		45,954,808		$	27,853			$	10,007			$	735,742			$	14,521			$	(104,944	)		$	—			$	(32,337	)		$	650,842
Issuance of common units		—			—		2,689,765			—				—				16,142				—				—				—				—				16,142
Redemption of Class A cumulative convertible preferred limited partner units		(25,000	)		—		—			(25,000	)			—				—				—				—				—				—				(25,000	)
Conversion of Class A cumulative convertible preferred limited partner units		(5,000	)		—		1,465,653			(2,528	)			—				2,528				—				—				—				—				—
Issuance of Class B preferred limited partner units		—			5,000		—			—				4,955				—				—				—				—				—				4,955
General partner capital contribution		—			—		—			—				—				—				658				—				—				—				658
Distributions to non-controlling interests		—			—		—			—				—				—				—				—				—				7				7
Unissued common units under incentive plans		—			—		—			—				—				497				—				—				—				—				497
Issuance of common units under incentive plans		—			—		394,752			—				—				—				—				—				—				—				—
Distributions paid to common limited partners, the general partner and preferred limited partners		—			—		—			(775	)			(457	)			(24,612	)			(505	)			—				—				—				(26,349	)
Purchase of Class B cumulative preferred member units of Atlas Pipeline Holdings II, LLC (reported as treasury units)		—			—		—			—				—				—				—				—				(15,000	)			—				(15,000	)
Distribution equivalent rights paid on unissued units under incentive plans		—			—		—			—				—				(59	)			—				—				—				—				(59	)
Other comprehensive income		—			—		—			—				—				—				—				43,802				—				—				43,802
Net income		—			—		—			450				450				92,957				1,907				—				—				2,075				97,839
Balance at September 30, 2009		—			15,000		50,504,978		$	—			$	14,955			$	823,195			$	16,581			$	(61,142	)		$	(15,000	)		$	(30,255	)		$	748,334

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. 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)		$	97,839			$	(118,125	)
Less: Income from discontinued operations			62,495				21,029
Net income (loss) from continuing operations			35,344				(139,154	)
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by (used in) operating activities:
Depreciation and amortization			67,563				61,200
Non-cash (gain) loss on derivative value, net			23,989				(57,009	)
Equity income in joint venture			(2,140	)			—
Gain on asset sales			(111,440	)			—
Distributions received from joint venture			1,657				—
Non-cash compensation expense (income)			497				(14,274	)
Amortization of deferred finance costs			6,449				3,650
Net distributions received from (paid to) non-controlling interests			7				(7,905	)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable, prepaid expenses and other			24,500				12,484
Accounts payable and accrued liabilities			(13,207	)			30,597
Accounts payable and accounts receivable – affiliates			1,335				9,421
Net cash provided by (used in) continuing operations			34,554				(100,990	)
Net cash provided by discontinued operations			16,935				37,474
Net cash provided by (used in) operating activities			51,489				(63,516	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition purchase price adjustment			—				31,429
Capital expenditures			(137,610	)			(223,768	)
Net proceeds from asset sales			110,355				—
Other			(4,551	)			1,095
Net cash used in continuing investing activities			(31,806	)			(191,244	)
Net cash provided by (used in) discontinued investing activities			290,594				(22,626	)
Net cash provided by (used in) investing activities			258,788				(213,870	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of debt			—				244,854
Repayment of debt			(273,675	)			(122,847	)
Borrowings under credit facility			483,000				576,000
Repayments under credit facility			(470,000	)			(506,000	)
Net proceeds from issuance of Class B preferred limited partner units			4,955				—
Net proceeds from issuance of common limited partner units			16,142				256,961
Redemption of Class A preferred units			(15,000	)			—
General partner capital contributions			658				5,452
Purchase of Class B cumulative preferred units of Atlas Pipeline Holdings II, LLC			(15,000	)			—
Distributions paid to common limited partners and the general partner			(26,349	)			(139,674	)
Other			(11,192	)			(5,963	)
Net cash provided by (used in) financing activities			(306,461	)			308,783
Net change in cash and cash equivalents			3,816				31,397
Cash and cash equivalents, beginning of period			1,445				12,341
Cash and cash equivalents, end of period		$	5,261			$	43,738

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2009

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Pipeline Partners, L.P. (the “Partnership”) is a publicly-traded (NYSE: APL) Delaware limited partnership engaged in the transmission, gathering and processing of natural gas. The Partnership’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”), a wholly-owned subsidiary of the Partnership. Atlas Pipeline Partners GP, LLC (the “General Partner”), through its general partner interests in the Partnership and the Operating Partnership, owns a 2% general partner interest in the consolidated pipeline operations, through which it manages and effectively controls both the Partnership and the Operating Partnership. The remaining 98% ownership interest in the consolidated pipeline operations consists of limited partner interests. The General Partner also owns 5,754,253 common limited partner units in the Partnership (see Note 5) and 15,000 $1,000 par value Class B preferred limited partner units (see Note 6). At September 30, 2009, the Partnership had 50,504,978 common limited partnership units outstanding, including the 5,754,253 common units held by the General Partner, and 15,000 $1,000 par value Class B preferred units held by the General Partner.

The Partnership’s General Partner is a wholly-owned subsidiary of Atlas Pipeline Holdings, L.P. (“AHD”), a publicly-traded partnership (NYSE: AHD). Atlas Energy, Inc. and its affiliates (“Atlas Energy”), a publicly-traded company (NASDAQ: ATLS) which owns a 64.4% ownership interest in AHD at September 30, 2009, also owns 1,112,000 of the Partnership’s common limited partnership units, representing a 2.2% ownership interest in the Partnership. On September 29, 2009, Atlas America, Inc., the former name of Atlas Energy, and Atlas Energy Resources, LLC (“Atlas Energy Resources”), a former publicly-traded Delaware limited liability company, executed a definitive merger agreement, pursuant to which Atlas America merged with Atlas Energy Resources (the “Merger”), with Atlas Energy Resources surviving as Atlas America’s wholly-owned subsidiary. Additionally, Atlas America changed its name to Atlas Energy, Inc. upon completion of the Merger.

The majority of the natural gas that the Partnership and its affiliates, including Laurel Mountain Midstream LLC (“Laurel Mountain”), transport in the Appalachian basin is derived from wells operated by Atlas Energy Resources. Laurel Mountain, which was formed in May 2009, is a joint venture between the Partnership and The Williams Companies, Inc. (NYSE: WMB) (“Williams”) in which the Partnership retains 49% ownership interest and Williams retains the remaining 51% ownership interest (see Note 3).

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 Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has evaluated subsequent events through November 5, 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 Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008. On May 4, 2009, the Partnership completed the sale of its NOARK gas gathering and interstate pipeline system (see Note 4). As such, the Partnership has adjusted the 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 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.

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

SEPTEMBER 30, 2009

(Unaudited)

 

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Partnership’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 Partnership, the Operating Partnership and the Operating Partnership’s wholly-owned and majority-owned subsidiaries. The General Partner’s interest in the Operating Partnership is reported as part of its overall 2% general partner interest in the Partnership. All material intercompany transactions have been eliminated.

The Partnership’s consolidated financial statements also include its 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. The Partnership consolidates 100% of these joint ventures and reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests and as a component of partners’ capital 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 Partnership’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, the Partnership’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 Partnership’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 Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depreciation and amortization, asset impairment, the fair value of derivative instruments, the probability of forecasted transactions, the allocation of purchase price to the fair value of assets acquired and other items. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity 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).

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

SEPTEMBER 30, 2009

(Unaudited)

 

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of net income (loss) attributable to participating securities and the general partner’s and the preferred unitholder’s interests, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its 2% interest and incentive distributions (see Note 8), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests.

The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, 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. The two-class method 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. Under the two-class method, management of the Partnership believes that the partnership agreement contractually limits cash distributions to available cash and, therefore, undistributed earnings are not allocated to the incentive distribution rights.

The two-class method 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 Earnings per Share (“EPS”) pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan and incentive compensation agreements (see Note 15), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. As such, the net income (loss) utilized in the calculation of net income (loss) per unit must be after the allocation of income (loss) to the phantom units on a pro-rata basis. The two-class method requires entities to retroactively adjust all prior period earnings per unit computations per its guidance.

The following is a reconciliation of net income (loss) from continuing operations and net income from discontinued operations allocated to the general partner and common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except per unit data):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008(1)				2009				2008(1)
Continuing operations:
Net income (loss)		$	(12,323	)		$	194,626			$	35,344			$	(139,154	)
Income attributable to non-controlling interest			(954	)			(2,591	)			(2,075	)			(7,793	)
Preferred unit dividends			—				(650	)			(900	)			(1,437	)
Preferred unit imputed dividend cost			—				—				—				(505	)
Net income (loss) attributable to common limited partners and the general partner			(13,277	)			191,385				32,369				(148,889	)
General partner’s actual cash incentive distributions declared			—				8,238				—				23,472
General partner’s actual 2% ownership interest			(266	)			3,681				651				(3,464	)
Net income (loss) attributable to the general partner’s ownership interests			(266	)			11,919				651				20,008
Net income (loss) attributable to common limited partners			(13,011	)			179,466				31,718				(168,897	)
Less: net income (loss) attributable to participating securities – phantom units(2)			(18	)			565				60				(610	)
Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit		$	(12,993	)		$	178,901			$	31,658			$	(168,287	)
Discontinued operations:
Net income		$	—			$	6,538			$	62,495			$	21,029
Net income attributable to the general partner’s ownership interests (2% ownership interest)			—				132				1,256				423
Net income utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit		$	—			$	6,406			$	61,239			$	20,606

 

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SEPTEMBER 30, 2009

(Unaudited)

 

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

(2)	Net income (loss) attributable to common limited partners’ ownership interest is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding).

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income (loss) allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plan (see Note 15). The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):

 

		Three Months Ended September 30,				Nine Months Ended September 30,
		2009		2008		2009		2008
Weighted average common limited partner units – basic		49,127		45,937		47,554		41,360
Add: effect of dilutive option incentive awards(1)		—		—		1		—
Add: effect of dilutive unit warrants(1)		—		—		36		—
Add: effect of dilutive convertible preferred limited partner units(1)		—		1,266		—		—
Weighted average common limited partner units – diluted		49,127		47,203		47,591		41,360

 

(1)

For the three months ended September 30, 2009, potential common limited partner units issuable upon exercise of the Partnership’s unit warrants (see Note 5) were excluded from computation of diluted net loss attributable to common limited partners as the impact of the conversion would have been anti-dilutive. There were no unit options or unit warrants outstanding for the three or nine months ended September 30, 2008. For the nine months ended September 30, 2008, potential common limited partner units issuable upon conversion of the Partnership’s Class A cumulative convertible preferred limited partner units were excluded from the computation of diluted net loss attributable to common limited partners as the impact of the conversion would have been anti-dilutive (see Note 6 for additional information regarding the conversion features of the preferred limited partner units).

 

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(Unaudited)

 

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and include only changes in the fair value of unsettled derivative contracts, which are accounted for as cash flow hedges. The following table sets forth the calculation of the Partnership’s comprehensive income (loss) (in thousands):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Net income (loss)		$	(12,323	)		$	201,164			$	97,839			$	(118,125	)
Income attributable to non-controlling interests			(954	)			(2,591	)			(2,075	)			(7,793	)
Preferred unit dividends			—				(650	)			(900	)			(1,437	)
Preferred unit imputed dividend cost			—				—				—				(505	)
Net income (loss) attributable to common limited partners and the general partner			(13,277	)			197,923				94,864				(127,860	)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as hedges			30				11,894				(2,268	)			(97,515	)
Add: adjustment for realized losses reclassified to net income (loss)			13,351				10,026				46,070				46,332
Total other comprehensive income (loss)			13,381				21,920				43,802				(51,183	)
Comprehensive income (loss)		$	104			$	219,843			$	138,666			$	(179,043	)

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or 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.

Revenue Recognition

The Partnership’s revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, the Partnership 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, the Partnership 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 the Partnership’s gathering and processing operations, it 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. The Partnership’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.

 

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(Unaudited)

 

POP Contracts. These contracts provide for the Partnership 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, the Partnership and the producer are directly dependent on the volume of the commodity and its value; the Partnership owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require the Partnership, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, the Partnership 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 the Partnership’s keep-whole contracts is minimized.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from the Partnership’s records and management estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at September 30, 2009 and December 31, 2008 of $43.1 million and $50.1 million, respectively, which are included in accounts receivable and accounts receivable-affiliates within its consolidated balance sheets.

Capitalized Interest

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 7.4% and 6.3% for the three months ended September 30, 2009 and 2008, respectively, and 6.0% and 6.3% for the nine months ended September 30, 2009 and 2008, respectively. The amount of interest capitalized was $0.6 million and $1.8 million for the three months ended September 30, 2009 and 2008, respectively, and $2.5 million and $5.3 million for the nine months ended September 30, 2009 and 2008, respectively.

Intangible Assets

The Partnership has recorded intangible assets with finite lives in connection with certain consummated acquisitions. The following table reflects the components of intangible assets being amortized at September 30, 2009 and December 31, 2008 (in thousands):

 

		September 30, 2009				December 31, 2008				Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts		$	12,810			$	12,810			8
Customer relationships			222,572				222,572			7–20
		$	235,382			$	235,382
Accumulated Amortization:
Customer contracts		$	(6,999	)		$	(5,806	)
Customer relationships			(53,903	)			(35,929	)
		$	(60,902	)		$	(41,735	)
Net Carrying Amount:
Customer contracts		$	5,811			$	7,004
Customer relationships			168,669				186,643
		$	174,480			$	193,647

 

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The Partnership amortizes intangible assets with finite useful lives over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, the Partnership will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for the Partnership’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for the Partnership’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for management’s estimate of whether these individual relationships will continue in excess or less than the average length. Amortization expense on intangible assets was $6.4 million for both the three month periods ended September 30, 2009 and 2008, and $19.2 million for both the nine month periods ended September 30, 2009 and 2008. Amortization expense related to intangible assets is estimated to be as follows for each of the next five calendar years: 2010 to 2012 - $25.6 million; 2013 - $24.5 million; 2014 - $20.4 million.

Goodwill

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		$	—		$	709,283
Post-closing purchase price adjustment with seller and purchase price allocation adjustment - Chaney Dell and Midkiff/Benedum acquisition			—			(2,217	)
Recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/ Benedum acquisition			—			(30,206	)
Balance, end of period		$	—		$	676,860

 

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(Unaudited)

 

As a result of its impairment evaluation at December 31, 2008, the Partnership recognized a $676.9 million non-cash impairment charge within its consolidated statements of operations during the fourth quarter of 2008. The goodwill impairment resulted from the reduction in the Partnership’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. The Partnership’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.

During April 2008, the Partnership 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 received in April 2008, the Partnership reduced goodwill recognized in connection with the acquisition at June 30, 2008.

Recently Adopted Accounting Standards

In August 2009, the 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 Partnership 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 Partnership 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. The Partnership adopted the requirements of Update 2009-01 to its financial statements on September 30, 2009 and it did not have a material impact on its financial statement disclosures.

 

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SEPTEMBER 30, 2009

(Unaudited)

 

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 Partnership 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 Partnership’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 Partnership adopted the requirements of ASC 820-10-65-4 on April 1, 2009 and its adoption did not have a material impact on its 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 Partnership adopted these requirements on April 1, 2009 and its adoption did not have a material impact on its 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 Partnership adopted these requirements on April 1, 2009 and its adoption did not have a material impact on its 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

 

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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 Partnership). The Partnership adopted the requirements on January 1, 2009 and its adoption did not have a material impact on its financial position and results of operations.

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 Partnership adopted the requirements on January 1, 2009 and its adoption did not have a material impact on its 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 Partnership 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 Partnership’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 Partnership 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 Partnership adopted the requirements of ASC 260-10-55-103 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 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 Partnership 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 11).

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

 

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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 Partnership 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 Partnership 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 Partnership 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 Partnership). The Partnership 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.

NOTE 3 – INVESTMENT IN JOINT VENTURE

On May 31, 2009, the Partnership and subsidiaries of Williams completed the formation of Laurel Mountain, a joint venture which owns and operates the Partnership’s Appalachia Basin natural gas gathering system, excluding the Partnership’s Northern Tennessee operations. Williams contributed cash of $100.0 million to the joint venture (of which the Partnership received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. The Partnership contributed the Appalachia Basin natural gas gathering system and retained a 49% ownership interest in Laurel Mountain. The Partnership is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51%

 

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ownership interest in Laurel Mountain. Upon completion of the transaction, the Partnership recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on its consolidated balance sheet at fair value. During the nine months ended September 30, 2009, the Partnership recognized a gain on sale of $108.9 million, including $54.2 million associated with the remeasurement of the Partnership’s investment in Laurel Mountain to fair value. The Partnership used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 13). In addition, Atlas Energy Resources sold two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania to Laurel Mountain for $10.0 million. Upon the completion of the contribution of the Partnership’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with Atlas Energy Resources which superseded the existing natural gas gathering agreements and omnibus agreement between the Partnership and Atlas Energy Resources. Under the new gas gathering agreement, Atlas Energy Resources 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 investment drilling partnerships’ gas). The Partnership 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 as equity income on its 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 Ended September 30, 2009			Nine Months Ended 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

 

(1)	Represents the period from May 31, 2009, the date of initial formation, through September 30, 2009.

NOTE 4 – DISCONTINUED OPERATIONS

On May 4, 2009, the Partnership 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 $294.5 million in cash, net of working capital adjustments. The Partnership used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 13). The Partnership accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $51.1 million on the sale of the NOARK assets within income from discontinued operations on its consolidated statements of operations during the nine months ended September 30, 2009. The following table summarizes the components included within income from discontinued operations on the Partnership’s consolidated statements of operations (amounts in thousands):

 

		Three Months Ended September 30,							Nine Months Ended September 30,
		2009			2008				2009				2008
Total revenue and other income (loss), net		$	—		$	13,468			$	21,274			$	45,827
Total costs and expenses			—			(6,930	)			(9,857	)			(24,798	)
Income from discontinued operations		$	—		$	6,538			$	11,417			$	21,029

 

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The following table summarizes the components included within total assets and liabilities of discontinued operations within the Partnership’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 5 – COMMON UNIT EQUITY OFFERINGS

In August 2009, the Partnership sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. The Partnership also received a capital contribution from AHD of $0.4 million for AHD to maintain its 2.0% general partner interest in the Partnership. In addition, the Partnership issued warrants granting investors in its private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. The Partnership utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 13), and will make similar repayments with net proceeds from future exercises of the warrants.

The common units and warrants sold by the Partnership in the August 2009 private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required the Partnership to (a) file a registration statement with the Securities and Exchange Commission for the privately placed common units and those underlying the warrants by September 21, 2009 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by November 18, 2009. The Partnership filed a registration statement with the Securities and Exchange Commission in satisfaction of the registration requirements of the registration rights agreement on September 3, 2009, and the registration statement was declared effective on October 14, 2009.

 

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In June 2008, the Partnership sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the Partnership sold 1,112,000 common units to Atlas Energy and 278,000 common units to AHD in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. The Partnership also received a capital contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in the Partnership. The Partnership utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements (see Note 11).

NOTE 6 – PREFERRED UNIT EQUITY OFFERINGS

Class A Preferred Units

In January 2009, the Partnership and Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, agreed to amend certain terms of the preferred unit certificate of designation for the then-outstanding 30,000 $1,000 par value 12.0% cumulative convertible Class A preferred units of limited partner interests (the “Class A Preferred Units”), which was initially entered into in March 2006. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, (b) established a new conversion commencement date on the outstanding Class A Preferred Units of April 1, 2009, (c) established Sunlight Capital’s new conversion option price of $22.00, enabling the Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of the Partnership’s common units, and (d) established a new price for the Partnership’s call redemption right of $27.25.

The amendment to the preferred units certificate of designation also required that the Partnership issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 (see Note 13) to redeem 10,000 Class A Preferred Units. Management of the Partnership estimated that the fair value of the $15.0 million 8.125% senior unsecured notes issued to redeem the Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded senior notes. As such, the Partnership recorded the redemption by recognizing a $10.0 million reduction of Class A Preferred equity within Partners’ Capital, $15.0 million of additional long-term debt for the face value of the senior unsecured notes issued, and a $5.0 million discount on the issuance of the senior unsecured notes which is presented as a reduction of long-term debt on the Partnership’s consolidated balance sheet. The discount recognized upon issuance of the senior unsecured notes will be amortized to interest expense within the Partnership’s consolidated statements of operations over the term of the notes based upon the effective interest rate method.

The amendment to the preferred units certificate of designation also required that (a) the Partnership redeem 10,000 of the Class A Preferred Units for cash at the liquidation value on April 1, 2009 and (b) that if Sunlight Capital made a conversion request of the remaining 10,000 Class A Preferred Units between April 1, 2009 and June 1, 2009, the Partnership has the option of redeeming the Class A Preferred Units for cash at the stipulated liquidation value or converting the Class A Preferred Units into its common limited partner units at the stipulated conversion price. If Sunlight Capital made a conversion request subsequent to June 1, 2009, 5,000 of the 10,000 Class A Preferred Units would have been required to be redeemed in cash, while the Partnership had the option of redeeming the remaining 5,000 Class A Preferred Units in cash or converting the preferred units into its common limited partner units.

On April 1, 2009, the Partnership redeemed 10,000 of the Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $10.0 million, in accordance with the terms of the amended preferred units certificate of designation. Additionally on April 1, 2009, the Partnership paid Sunlight a preferred dividend of $0.3 million, representing the quarterly dividend on the 10,000 preferred units held by Sunlight prior to the Partnership’s redemption. On April 13, 2009, the Partnership converted 5,000 of the Class A Preferred Units into 1,465,653 Partnership common units in accordance with the terms of the amended preferred units certificate of designation. The Partnership reclassified $5.0 million from Class A preferred limited partner equity to common limited partner equity within partners’ capital when these preferred units were converted into common limited partner units. On May 5, 2009, the Partnership redeemed the remaining 5,000 Class A Preferred Units held by Sunlight

 

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Capital for cash at the liquidation value of $1,000 per unit, or $5.0 million, pursuant to the terms of the amended preferred units certificate of designation. Additionally on May 5, 2009, the Partnership paid Sunlight a preferred dividend of $0.2 million, representing the quarterly dividend on the 5,000 Class A Preferred Units held by Sunlight prior to the Partnership’s redemption.

In accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 68, “Increasing Rate Preferred Stock,” the initial issuances of the 40,000 Class A Preferred Units were recorded on the consolidated balance sheet at the amount of net proceeds received less an imputed dividend cost. As a result of an amendment to the preferred units certificate of designation in March 2007, the Partnership, in lieu of dividend payments to Sunlight Capital, recognized an imputed dividend cost of $2.5 million that was amortized over a twelve-month period commencing March 2007 and was based upon the present value of the net proceeds received using the then-6.5% stated dividend yield. During the three months ended March 31, 2008, the Partnership amortized the remaining $0.5 million of this imputed dividend cost, which is presented as an additional adjustment of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on its consolidated statements of operations for the nine months ended September 30, 2008.

The Partnership recognized $0.7 million of preferred dividend cost for the three months ended September 30, 2008 and $0.4 million and $1.4 million of preferred dividend cost for the nine months ended September 30, 2009 and 2008, respectively, for dividends paid to the Class A preferred units, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on its consolidated statements of operations.

Class B Preferred Units

In December 2008, the Partnership sold 10,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “Class B Preferred Units”) to AHD for cash consideration of $1,000 per Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “Class B Preferred Units Certificate of Designation”). On March 30, 2009, AHD, pursuant to its right within the Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 Class B Preferred Units at Face Value. The Partnership used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. The Class B Preferred Units receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for the Partnership’s common units. The record date of determination for holders entitled to receive distributions of the Class B Preferred Units will be the same as the record date of determination for common unit holders entitled to receive quarterly distributions. Additionally, on March 30, 2009, the Partnership and AHD agreed to amend the terms of the Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the Class B Preferred Units are not convertible into common units of the Partnership. The amended Class B Preferred Units Certificate of Designation also gives the Partnership the right at any time to redeem some or all of the outstanding Class B Preferred Units for cash at an amount equal to the Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 Class B Preferred Units or b) the number of remaining outstanding Class B Preferred Units.

The cumulative sale of the Class B Preferred Units to AHD was exempt from the registration requirements of the Securities Act of 1933. The Partnership recognized $0.5 million of preferred dividend cost for the nine months ended September 30, 2009, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on its consolidated statements of operations. The Class B Preferred Units are reflected on the Partnership’s consolidated balance sheet as Class B preferred equity within partners’ capital.

NOTE 7 – INVESTMENT IN ATLAS PIPELINE HOLDINGS II, LLC

In June 2009, the Partnership purchased 15,000 12.0% cumulative preferred units (the “preferred units”) from a newly-formed

 

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subsidiary of AHD, Atlas Pipeline Holdings II, LLC (“AHD II”) for cash consideration of $1,000 per unit, for an aggregate investment of $15.0 million at September 30, 2009. The preferred units receive cash distributions of 12.0% per annum, to be paid quarterly. However, per the terms of AHD’s amended agreement to its outstanding revolving credit facility, such distributions can be paid only upon AHD’s repayment of all of its outstanding borrowings under its credit facility, which will occur no later than April 13, 2010, the credit facility’s maturity date. Distributions on the Partnership’s preferred units held by AHD II prior to AHD’s repayment of all indebtedness under its credit facility will be paid by increasing the Partnership’s preferred unit investment in AHD II. AHD II has the option, beginning on April 14, 2010, to redeem all of its outstanding preferred units held by the Partnership for an amount equal to the Partnership’s then-current balance of its preferred unit investment. AHD used the proceeds from its preferred unit offering to the Partnership to reduce indebtedness under its credit facility. The Partnership accounted for the purchase of the preferred units as treasury units, with the investment reflected at cost as a reduction of partners’ capital within its consolidated balance sheet.

NOTE 8 – CASH DISTRIBUTIONS

The Partnership is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the General Partner. If common unit distributions in any quarter exceed specified target levels, the General Partner will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and General Partner distributions declared by the Partnership for the period from January 1, 2008 through September 30, 2009 were as follows:

 

Date Cash Distribution Paid		For Quarter Ended		Cash Distribution Per Common Limited Partner Unit			Total Cash Distribution to Common Limited Partners			Total Cash Distribution to the General Partner
							(in thousands)			(in thousands)
February 14, 2008		December 31, 2007		$	0.93		$	36,051		$	5,092
May 15, 2008		March 31, 2008		$	0.94		$	36,450		$	7,891
August 14, 2008		June 30, 2008		$	0.96		$	44,096		$	9,308
November 14, 2008		September 30, 2008		$	0.96		$	44,105		$	9,312
February 13, 2009		December 31, 2008		$	0.38		$	17,463		$	358
May 15, 2009		March 31, 2009		$	0.15		$	7,149		$	147

The Partnership did not declare a cash distribution for the quarters ended September 30 and June 30, 2009. On May 29, 2009, the Partnership entered into an amendment to its senior secured credit facility (see Note 13) which, among other changes, requires that it pay no cash distributions for the remainder of the year ended December 31, 2009 and allows it to pay cash distributions for the period beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

In connection with the Partnership’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems in July 2007, AHD, which holds all of the incentive distribution rights in the Partnership, agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to the Partnership. AHD also agreed that the resulting allocation of incentive distribution rights back to the Partnership would be after AHD receives the initial $7.0 million per quarter of incentive distribution rights.

 

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NOTE 9 – PROPERTY, PLANT AND EQUIPMENT

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

 

		September 30, 2009				December 31, 2008(1)				Estimated Useful Lives in Years
Pipelines, processing and compression facilities		$	1,643,798			$	1,707,046			15 – 40
Rights of way			166,826				168,057			20 – 40
Buildings			8,920				8,920			40
Furniture and equipment			9,458				9,279			3 – 7
Other			12,837				13,002			3 – 10
			1,841,839				1,906,304
Less – accumulated depreciation			(143,613	)			(125,293	)
		$	1,698,226			$	1,781,011

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

On July 13, 2009, the Partnership sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse the Partnership for its proportionate share of the operating expenses. The Partnership will continue to operate the facility. The Partnership used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility (see Note 13). The Partnership recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on the Partnership’s consolidated statements of operations.

NOTE 10 – OTHER ASSETS

The following is a summary of other assets (in thousands):

 

		September 30, 2009			December 31, 2008(1)
Deferred finance costs, net of accumulated amortization of $23,747 and $17,298 at September 30, 2009 and December 31, 2008, respectively		$	28,658		$	23,676
Long-term pipeline lease prepayment			2,606			—
Security deposits			3,674			1,317
		$	34,938		$	24,993

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 13). During the nine months ended September 30, 2009 and 2008, the Partnership recorded $2.5 million and $1.2 million, respectively, of accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan, which is recorded within interest expense on the Partnership’s consolidated statements of operations.

NOTE 11 – DERIVATIVE INSTRUMENTS

The Partnership uses a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. The Partnership enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. It also enters into financial swap instruments to hedge certain portions of its floating interest rate debt

 

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(Unaudited)

 

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 and condensate are sold or interest payments on the underlying debt instrument are due. Under swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant contract period.

The Partnership formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching derivative contracts to the forecasted transactions. The Partnership assesses, 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 Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Partnership through the utilization of market data, will be recognized within other income (loss), net in its consolidated statements of operations. For derivatives previously qualifying as hedges, the Partnership recognized the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss) and reclassified the portion relating to commodity derivatives to natural gas and liquids revenue and the portion relating to interest rate derivatives to interest expense within its consolidated statements of operations as the underlying transactions were settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss), net in its consolidated statements of operations as they occur.

Beginning July 1, 2008, the Partnership discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in its consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

At September 30, 2009, the Partnership had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, the Partnership will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its credit facility (see Note 13), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreements were in effect as of September 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, the Partnership discontinued hedge accounting for its interest rate derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in the fair value of these derivatives will be recognized immediately within other income (loss), net in its consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

Derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. At September 30, 2009 and December 31, 2008, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $43.8 million and $63.6 million, respectively. Of the $61.1 million of net loss in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet at September 30, 2009, the Partnership will reclassify $36.1 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period, consisting of $31.0 million of losses to natural gas and liquids revenue and $5.1 million of losses to interest expense. Aggregate losses of $25.0 million will be reclassified to the Partnership’s consolidated statements of operations in later periods, all consisting of losses to natural gas and liquids revenue.

 

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The fair value of the Partnership’s derivative instruments was included in its consolidated balance sheets as follows (in thousands):

 

		September 30, 2009				December 31, 2008
Current portion of derivative asset		$	4,514			$	44,961
Long-term derivative asset			1,980				—
Current portion of derivative liability			(41,019	)			(60,396	)
Long-term derivative liability			(9,256	)			(48,159	)
		$	(43,781	)		$	(63,594	)

During the nine months ended September 30, 2009 and year ended December 31, 2008, the Partnership made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. Substantially all of these derivative contracts were put into place simultaneously with the Partnership’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the three and nine months ended September 30, 2009 and 2008, the Partnership recognized the following derivative activity related to the termination of these derivative instruments within its consolidated statements of operations (amounts in thousands):

 

		Early Termination of Derivative Contracts
		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Net cash derivative expense included within other income (loss), net		$	—			$	(70,258	)		$	(5,000	)		$	(186,068	)
Net cash derivative expense included within natural gas and liquids revenue		$	—			$	(1,258	)		$	—			$	(1,573	)
Net non-cash derivative income (expense) included within other income (loss), net		$	15,488			$	6,488			$	34,708			$	(39,857	)
Net non-cash derivative expense included within natural gas and liquids		$	(19,976	)		$	(19,514	)		$	(54,043	)		$	(19,514	)

In addition, $6.6 million will be reclassified from accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet and recognized as non-cash derivative expenses during the period beginning on October 1, 2009 and ending on December 31, 2009, the remaining period for which the derivatives were originally scheduled to be settled, as a result of the early termination of certain derivatives that were classified as cash flow hedges at the date of termination.

 

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The following table summarizes the Partnership’s derivative activity, including the early termination of derivative contracts disclosed above, for the periods indicated (amounts in thousands):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Loss from cash settlement and non-cash recognition of qualifying hedge instruments(1)		$	(9,779	)		$	(27,419	)		$	(37,281	)		$	(78,214	)
Gain (loss) from change in market value of non- qualifying derivatives(2)		$	12,021			$	190,013			$	(30,460	)		$	(17,919	)
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2)		$	—			$	44,997			$	10,813			$	41,271
Gain (loss) from cash settlement and non-cash recognition of non-qualifying derivatives(2)		$	(10,165	)		$	(84,207	)		$	3,225			$	(280,696	)
Loss from cash settlement of qualifying interest rate derivatives(3)		$	(3,148	)		$	(673	)		$	(9,003	)		$	(867	)
Loss from change in market value of non-qualifying interest rate derivatives (2)		$	(823	)		$	—			$	(823	)		$	—

 

(1)	Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations.

(2)	Included within other income (loss), net on the Partnership’s consolidated statements of operations.

(3)	Included within interest expense on the Partnership’s consolidated statements of operations.

The following table summarizes the Partnership’s gross fair values of derivative instruments for the period indicated (amounts in thousands):

 

		September 30, 2009
		Asset Derivatives					Liability Derivatives
		Balance Sheet Location		Fair Value			Balance Sheet Location		Fair Value
Derivatives not designated as hedging instruments:
Interest rate contracts		N/A		$	—		Current portion of derivative liability		$	(5,907	)
Commodity contracts		Current portion of derivative asset			4,514
Commodity contracts		Long-term derivative asset			1,980
Commodity contracts		Current portion of derivative liability			10,050		Current portion of derivative liability			(45,162	)
Commodity contracts		Long-term derivative liability			3,341		Long-term derivative liability			(12,597	)
				$	19,885				$	(63,666	)

The following table summarizes the gross effect of derivative instruments on the Partnership’s consolidated statement of operations for the period indicated (amounts in thousands):

 

		Derivatives not designated as hedging instruments Three months ended September 30, 2009
		Gain (Loss) Recognized in Accumulated OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)						Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
					Amount				Location		Amount				Location
Interest rate contracts(1)		$	30		$	(3,057	)		Interest expense		$	(823	)		N/A
Commodity contracts(1)			—			(10,294	)		Natural gas and liquids revenue			(13,671	)		Other income (loss), net
Commodity contracts(2)			—			—			N/A			16,036			Other income (loss), net
		$	30		$	(13,351	)				$	1,542

 

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(1)	Hedges previously designated as cash flow hedges

(2)	Dedesignated cash flow hedges and non-designated hedges

 

		Derivatives not designated as hedging instruments Nine months ended September 30, 2009
		Gain (Loss) Recognized in Accumulated OCI				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)						Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
						Amount				Location		Amount				Location
Interest rate contracts(1)		$	(2,268	)		$	(8,912	)		Interest expense		$	(823	)		N/A
Commodity contracts(1)			—				(37,158	)		Natural gas and liquids revenue			(36,579	)		Other income (loss), net
Commodity contracts(2)			—				—			N/A			20,155			Other income (loss), net
		$	(2,268	)		$	(46,070	)				$	(17,247	)

 

(1)	Hedges previously designated as cash flow hedges

(2)	Dedesignated cash flow hedges and non-designated hedges

As of September 30, 2009, the Partnership had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

 

Term		Notional Amount			Type		Contract Period Ended December 31,		Fair Value Liability(1)
									(in thousands)
January 2008- January 2010		$	200,000,000		Pay 2.88% —Receive LIBOR		2009		$	(1,335	)
							2010			(426	)
									$	(1,761	)
April 2008- April 2010		$	250,000,000		Pay 3.14% —Receive LIBOR		2009		$	(1,832	)
							2010			(2,314	)
									$	(4,146	)

Natural Gas Sales – Fixed Price Swaps

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Asset (3)
2009		120,000		$	8.000		$	390

Natural Gas Basis Sales

 

Production Period Ended December 31,		Volumes		Average Fixed Price				Fair Value Liability (3)
		(mmbtu)(6)		(per mmbtu)(6)				(in thousands)
2009		1,230,000		$	(0.558	)		$	(386	)
2010		2,220,000		$	(0.607	)			(401	)
								$	(787	)

 

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SEPTEMBER 30, 2009

(Unaudited)

 

Natural Gas Purchases – Fixed Price Swaps

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability (3)
		(mmbtu)(6)		(per mmbtu)(6)			(in thousands)
2009		2,580,000		$	8.687		$	(10,162	)
2010		4,380,000		$	8.635			(11,718	)
							$	(21,880	)

Natural Gas Basis Purchases

 

Production Period Ended December 31,		Volumes		Average Fixed Price				Fair Value Asset(3)
		(mmbtu)(6)		(per mmbtu)(6)				(in thousands)
2009		3,690,000		$	(0.659	)		$	1,508
2010		6,600,000		$	(0.590	)			1,193
								$	2,701

Natural Gas Liquids – Fixed Price Swap

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability(2)
		(gallons)		(per gallon)			(in thousands)
2009		5,544,000		$	0.754		$	(762	)

Ethane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Liability(1)				Option Type
		(gallons)		(per gallon)			(in thousands)
2009		630,000		$	0.340		$	(57	)		Puts purchased

Propane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Asset(1)			Option Type
		(gallons)		(per gallon)			(in thousands)
2009		15,246,000		$	0.820		$	579		Puts purchased

Isobutane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Liability(1)				Option Type
		(gallons)		(per gallon)			(in thousands)
2009		126,000		$	0.5890		$	(20	)		Puts purchased

Normal Butane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Asset(1)			Option Type
		(gallons)		(per gallon)			(in thousands)
2009		3,654,000		$	0.943		$	98		Puts purchased
2010		3,654,000		$	1.038		$	544		Puts purchased
							$	642

 

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SEPTEMBER 30, 2009

(Unaudited)

 

Natural Gasoline Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Asset(1)			Option Type
		(gallons)		(per gallon)			(in thousands)
2009		3,906,000		$	1.341		$	549		Puts purchased
2010		3,906,000		$	1.345		$	902		Puts purchased
							$	1,451

Crude Oil Sales Options (associated with NGL volume)

 

Production Period Ended December 31,		Crude Volume		Associated NGL Volume		Average Crude Price (4)			Fair Value Asset (Liability)(3)				Option Type
		(barrels)		(gallons)		(per barrel)			(in thousands)
2009		165,000		9,321,900		$	63.53		$	856			Puts purchased
2009		527,700		29,874,978		$	84.80			(647	)		Calls sold
2010		486,000		27,356,700		$	61.24			4,111			Puts purchased
2010		3,127,500		213,088,050		$	86.20			(20,462	)		Calls sold
2010		714,000		45,415,440		$	132.17			705			Calls purchased(5)
2011		606,000		33,145,560		$	100.70			(4,517	)		Calls sold
2011		252,000		13,547,520		$	133.16			920			Calls purchased(5)
2012		450,000		25,893,000		$	102.71			(4,038	)		Calls sold
2012		180,000		9,676,800		$	134.27			919			Calls purchased(5)
									$	(22,153	)

Crude Oil Sales

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability(3)
		(barrels)		(per barrel)			(in thousands)
2009		6,000		$	62.700		$	(48	)

Crude Oil Sales Options

 

Production Period Ended December 31,		Volumes		Average Crude Price(4)			Fair Value Asset (Liability)(3)				Option Type
		(barrels)		(per barrel)			(in thousands)
2009		117,000		$	64.151		$	604			Puts purchased
2009		76,500		$	84.956			(116	)		Calls sold
2010		411,000		$	64.732			4,450			Puts purchased
2010		234,000		$	88.088			(1,475	)		Calls sold
2011		72,000		$	93.109			(746	)		Calls sold
2012		48,000		$	90.314			(647	)		Calls sold
							$	2,070
		Total net liability					$	(43,781	)

 

(1)	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

 

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(Unaudited)

 

(2)	Fair value based upon management estimates, including forecasted forward NGL prices.

(3)	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

(4)	Average price of options based upon average strike price adjusted by average premium paid or received.

(5)	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

(6)	Mmbtu represents million British Thermal Units.

NOTE 12 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1– Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

The Partnership uses a fair value methodology to value the assets and liabilities for its respective outstanding derivative contracts (see Note 11). At September 30, 2009, all of the Partnership’s derivative contracts are defined as Level 2, with the exception of the Partnership’s NGL fixed price swaps and NGL options. The Partnership’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. The Partnership’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Valuations for the Partnership’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3. Valuations for the Partnership’s NGL options are based on forward price curves developed by the related financial institution, and therefore are defined at Level 3.

On June 30, 2009, the Partnership changed the basis for its valuation of crude oil options. Previously, the Partnership utilized forward price curves developed by its derivative counterparties. Effective June 30, 2009, the Partnership utilized crude oil option prices quoted from a public commodity exchange. With this change in valuation basis, the Partnership reclassified the inputs for the valuation of its crude oil options from a Level 3 input to a Level 2 input. The change in valuation basis did not materially impact the fair value of its derivative instruments on its consolidated statements of operations.

The following table represents the Partnership’s assets and liabilities recorded at fair value as of September 30, 2009 (in thousands):

 

		Level 1			Level 2				Level 3			Total
Commodity-based derivatives		$	—		$	(39,708	)		$	1,834		$	(37,874	)
Interest rate swap-based derivatives			—			(5,907	)			—			(5,907	)
Total		$	—		$	(45,615	)		$	1,834		$	(43,781	)

 

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(Unaudited)

 

The Partnership’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of the Partnership’s Level 3 derivative instruments as of September 30, 2009 (in thousands):

 

		NGL Fixed Price Swaps				NGL Sales Options				Crude Oil Options				Total
Balance – December 31, 2008		$	1,509			$	12,316			$	(23,436	)		$	(9,611	)
New options contracts			—				(2,896	)			—				(2,896	)
Cash settlements from unrealized gain (loss)(1)			(5,459	)			(9,866	)			(37,671	)			(52,996	)
Cash settlements from other comprehensive income(1)			5,453				—				11,618				17,071
Net change in unrealized gain (loss)(2)			(2,265	)			(1,084	)			14,886				11,537
Deferred option premium recognition			—				4,126				2,239				6,365
Net change in other comprehensive loss			—				—				—				—
Transfer to Level 2			—				—				32,364				32,364
Balance – September 30, 2009		$	(762	)		$	2,596			$	—			$	1,834

 

(1)	Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations.

(2)	Included within other income (loss), net on the Partnership’s consolidated statements of operations.

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments.

The Partnership’s other current assets and liabilities on its consolidated balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Partnership’s total debt at September 30, 2009 and December 31, 2008, which consists principally of the term loan, the Senior Notes and borrowings under the credit facility, were $1,137.9 million and $1,153.2 million, respectively, compared with the carrying amount of $1,243.1 million and $1,493.4 million, respectively. The term loan and Senior Notes were valued based upon available market data for similar issues. The carrying value of outstanding borrowings under the credit facility, which bear interest at a variable interest rate, approximates their estimated fair value.

NOTE 13 – DEBT

Total debt consists of the following (in thousands):

 

		September 30, 2009			December 31, 2008
Revolving credit facility		$	315,000		$	302,000
Term loan			433,505			707,180
8.125% Senior notes – due 2015			271,495			261,197
8.75% Senior notes – due 2018			223,050			223,050
Total debt			1,243,050			1,493,427
Less current maturities			—			—
Total long-term debt		$	1,243,050		$	1,493,427

 

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Term Loan and Revolving Credit Facility

At September 30, 2009, the Partnership has 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 the credit facility bear interest, at the Partnership’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 revolving credit facility borrowings at September 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding 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 Partnership’s consolidated balance sheet. At September 30, 2009, the Partnership has $55.9 million of remaining committed capacity under its credit facility, subject to covenant limitations.

On May 29, 2009, the Partnership 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 minimum ratio of interest coverage (as defined in the credit agreement) that the credit facility requires the Partnership 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 the Partnership to maintain;

 

•

required that the Partnership pay no cash distributions during the remainder of the year ended December 31, 2009 and allows the Partnership to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and has minimum liquidity (as defined in the credit agreement) of at least $50.0 million;

 

•

generally limits the Partnership’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;

 

•

permitted the Partnership 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 the Partnership’s leverage ratio.

 

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In June 2008, the Partnership 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 11) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, the Partnership 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 the Partnership’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.

Borrowings under the credit facility are secured by a lien on and security interest in all of the Partnership’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 the Partnership’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on the Partnership’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. The Partnership 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. The Partnership 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 the Partnership in excess of a specified amount, and a change of control of the Partnership’s General Partner. The credit facility requires the Partnership to maintain the following ratios:

 

Fiscal quarter ending:		Maximum Leverage Ratio		Maximum Senior Secured Leverage Ratio		Minimum Interest Coverage 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, the Partnership’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.

Senior Notes

At September 30, 2009, the Partnership had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“8.125% Senior Notes”; collectively, the “Senior Notes”). The Partnership’s 8.125% Senior Notes are presented

 

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SEPTEMBER 30, 2009

(Unaudited)

 

combined with a net $4.0 million of unamortized discount as of September 30, 2009. Interest on the Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, the Partnership may redeem up to 35% of the aggregate principal amount of the 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes in the aggregate are also subject to repurchase by the Partnership 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 the Partnership does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Partnership’s secured debt, including the Partnership’s obligations under its credit facility.

In January 2009, the Partnership issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 Class A Preferred Units (see Note 6). Management of the Partnership 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, the Partnership recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on its consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense within the Partnership’s consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

Indentures governing the Senior Notes in the aggregate contain covenants, including limitations of the Partnership’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. The Partnership is in compliance with these covenants as of September 30, 2009.

NOTE 14 – COMMITMENTS AND CONTINGENCIES

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership believes that the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.

As of September 30, 2009, the Partnership is committed to expend approximately $17.8 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 15 – BENEFIT PLANS

Long-Term Incentive Plan

The Partnership has a Long-Term Incentive Plan (“LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The Plan is administered by a committee (the “Committee”) appointed by General Partner’s managing board. The Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units.

Partnership Phantom Units. A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the Committee, cash equivalent to the fair market value of a common unit. In addition, the Committee may grant a participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase the Partnership’s common limited partner units at an exercise price determined by the Committee at its discretion. The Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of the

 

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(Unaudited)

 

General Partner, the Committee will determine the vesting period for phantom units and the exercise period for options. Through September 30, 2009, phantom units granted under the LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the LTIP. Of the units outstanding under the LTIP at September 30, 2009, 28,960 units will vest within the following twelve months. All phantom units outstanding under the LTIP at September 30, 2009 include DERs granted to the participants by the Committee. The amounts paid with respect to LTIP DERs were $0.1 million for the three months ended September 30, 2008, and $0.1 million and $0.4 million for the nine months ended September 30, 2009 and 2008, respectively. No LTIP DER payments were made for the three months ended September 30, 2009. These amounts were recorded as reductions of Partners’ Capital on the Partnership’s consolidated balance sheet.

Generally, all share-based payments to employees, including grants of employee stock options, are recognized in the financial statements based on their fair values.

The following table sets forth the LTIP phantom unit activity for the periods indicated:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Outstanding, beginning of period			76,721				149,923				126,565				129,746
Granted(1)			—				—				2,000				54,296
Matured(2)			(11,038	)			(10,860	)			(46,132	)			(44,229	)
Forfeited			(75	)			(1,000	)			(16,825	)			(1,750	)
Outstanding, end of period(3)			65,608				138,063				65,608				138,063
Non-cash compensation expense recognized (in thousands)		$	235			$	600			$	491			$	1,783

 

(1)

The weighted average prices for phantom unit awards on the date of grant, which are utilized in the calculation of compensation expense and do not represent an exercise price to be paid by the recipient, were $4.75 and $44.43 for awards granted for the nine months ended September 30, 2009 and 2008, respectively. There were no awards granted for the three months ended September 30, 2009 and 2008.

(2)	The intrinsic values for phantom unit awards vested during the three months ended September 30, 2009 and 2008 were $0.1 million and $0.4 million, respectively, and $0.2 million and $1.8 million during the nine months ended September 30, 2009 and 2008, respectively.

(3)	The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2009 was $0.5 million.

At September 30, 2009, the Partnership had approximately $0.8 million of unrecognized compensation expense related to unvested phantom units outstanding under the LTIP based upon the fair value of the awards.

 

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(Unaudited)

 

Partnership Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit as determined by the Committee on the date of grant of the option. The Committee also shall determine how the exercise price may be paid by the Participant. The Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through September 30, 2009, unit options granted under the Partnership’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP. There are 25,000 unit options outstanding under the Partnership’s LTIP at September 30, 2009 that will vest within the following twelve months. The following table sets forth the LTIP unit option activity for the periods indicated:

 

		Three Months Ended September 30,
		2009						2008
		Number of Unit Options			Weighted Average Exercise Price			Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period			100,000		$	6.24			—		$	—
Granted			—			—			—			—
Matured			—			—			—			—
Forfeited			—			—			—			—
Outstanding, end of period(1)(2)			100,000		$	6.24			—		$	—
Options exercisable, end of period			—			—			—			—
Weighted average fair value of unit options per unit granted during the period Weighted average fair value of unit			—		$	—			—		$	—
Non-cash compensation expense recognized (in thousands)		$	2					$	—
		Nine Months Ended September 30,
		2009						2008
		Number of Unit Options			Weighted Average Exercise Price			Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of period			—		$	—			—		$	—
Granted			100,000			6.24			—			—
Matured			—			—			—			—
Forfeited			—			—			—			—
Outstanding, end of period(1)(2)			100,000		$	6.24			—		$	—
Options exercisable, end of period			—			—			—			—
Weighted average fair value of unit options per unit granted during the period Weighted average fair value of unit			100,000		$	0.14			—		$	—
Non-cash compensation expense recognized (in thousands)		$	5					$	—

 

(1)	The weighted average remaining contractual life for outstanding options at September 30, 2009 was 9.3 years.

(2)	The aggregate intrinsic value of options outstanding at September 30, 2009 was $0.1 million.

 

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(Unaudited)

 

The Partnership used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:

 

		Nine Months Ended September 30, 2009
Expected dividend yield		11.0	%
Expected stock price volatility		20.0	%
Risk-free interest rate		2.2	%
Expected term (in years)		6.3

Incentive Compensation Agreements

The Partnership had incentive compensation agreements which granted awards to certain key employees retained from previously consummated acquisitions. These individuals were entitled to receive common units of the Partnership upon the vesting of the awards, which was dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total common units issued under the incentive compensation agreements, 58,822 common units were issued during the year ended December 31, 2007. The ultimate number of common units issued under the incentive compensation agreements was determined principally by the financial performance of certain Partnership assets during the year ended December 31, 2008 and the market value of the Partnership’s common units at December 31, 2008. The incentive compensation agreements also dictated that no individual covered under the agreements would receive an amount of common units in excess of one percent of the outstanding common units of the Partnership at the date of issuance. Common unit amounts due to any individual covered under the agreements in excess of one percent of the outstanding common units of the Partnership would have been paid in cash.

As of December 31, 2008, the Partnership recognized in full within its consolidated statements of operations the compensation expense associated with the vesting of awards issued under these incentive compensation agreements, therefore no compensation expense was recognized during the three and nine months ended September 30, 2009. The Partnership recognized reductions in compensation expense of $13.3 million and $16.1 million for the three and nine months ended September 30, 2008, respectively, related to the vesting of awards under these incentive compensation agreements. The non-cash compensation expense adjustments for the three and nine months ended September 30, 2008 were principally attributable to changes in the Partnership’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at September 30, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through September 30, 2008. The Partnership recognized compensation expense related to these awards based upon the fair value method. During the nine months ended September 30, 2009, the Partnership issued 348,620 common units to the certain key employees covered under the incentive compensation agreements. No additional common units will be issued with regard to these agreements.

Employee Incentive Compensation Plan and Agreement

In June 2009, a wholly-owned subsidiary of the Partnership adopted an incentive plan (the “Plan”) which allows for equity-indexed cash incentive awards to employees of the Partnership (the “Participants”), but expressly excludes as an eligible Participant any “Named Executive Officer” of the Partnership (as such term is defined under the rules of the Securities and Exchange Commission). The Plan is administered by a committee appointed by the chief executive officer of the Partnership. Under the Plan, cash bonus units may be awarded Participants at the discretion of the committee and bonus units totaling 325,000 were awarded under the Plan in June 2009. In September 2009, the subsidiary entered into an agreement with an executive officer that granted an award of 50,000 bonus units on substantially the same terms as the bonus units available under the Plan (the bonus units issued under the Plan and under the separate agreement are, for purposes hereof, referred to as “Bonus Units”). A Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of a common limited partner unit, without payment of an exercise price,

 

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upon vesting of the Bonus Unit. Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. During the three and nine months ended September 30, 2009, the Partnership granted 50,000 and 375,000 Bonus Units, respectively. Of the Bonus Units outstanding at September 30, 2009, 123,750 Bonus Units will vest within the following twelve months. The Partnership recognized compensation expense related to these awards based upon the fair value. The Partnership recognized $0.4 million and $0.5 million of compensation expense within general and administrative expense on its consolidated statements of operations with respect to the vesting of these awards for the three and nine months ended September 30, 2009, respectively. At September 30, 2009, the Partnership has recognized $0.5 million within accrued liabilities on its consolidated balance sheet with regard to the awards, which represents their fair value at September 30, 2009.

NOTE 16 – RELATED PARTY TRANSACTIONS

The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by the General Partner and employees of Atlas Energy. The General Partner does not receive a management fee in connection with its management of the Partnership apart from its interest as general partner and its right to receive incentive distributions. The Partnership reimburses the General Partner and its affiliates for compensation and benefits related to their employees who perform services for the Partnership based upon an estimate of the time spent by such persons on activities for the Partnership. Other indirect costs, such as rent for offices, are allocated to the Partnership by Atlas Energy based on the number of its employees who devote their time to activities on the Partnership’s behalf.

The Partnership agreement provides that the General Partner will determine the costs and expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner at its sole discretion. The Partnership reimbursed the General Partner and its affiliates $0.4 million and $1.2 million for the three months ended September 30, 2009 and 2008, respectively, and $1.1 million and $3.7 million for the nine months ended September 30, 2009 and 2008, respectively, for compensation and benefits related to their employees. There were no direct reimbursements to the General Partner and its affiliates for the three and nine months ended September 30, 2009 and 2008. The General Partner believes that the method utilized in allocating costs to the Partnership is reasonable.

NOTE 17 – SEGMENT INFORMATION

The Partnership has two reportable segments: natural gas transmission, gathering and processing assets located in the Mid-Continent area (“Mid-Continent”) of primarily Oklahoma, northern and western Texas, the Texas Panhandle and southern Kansas, and natural gas transmission, gathering and processing assets located in the Appalachian Basin area (“Appalachia”) of eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. Effective May 31, 2009, the Appalachia operations were principally conducted through the Partnership’s 49% ownership interest in Laurel Mountain, a joint venture to which the Partnership contributed its natural gas transmission, gathering and processing assets located in eastern Ohio, western New York, and western Pennsylvania. The Partnership recognizes its ownership interest in Laurel Mountain under the equity method of accounting. Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs and transport of natural gas. Appalachia revenues are principally based on contractual arrangements with Atlas Energy Resources and its affiliates. These reportable segments reflect the way the Partnership manages its operations.

 

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(Unaudited)

 

The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008(1)				2009				2008(1)
Mid-Continent
Revenue:
Natural gas and liquids		$	194,438			$	395,621			$	525,891			$	1,183,487
Transportation, compression and other fees			3,632				5,741				10,644				15,840
Gain on asset sale			2,493				—				2,493				—
Other income (loss), net			4,797				153,805				(5,838	)			(247,409	)
Total revenue and other income (loss), net			205,360				555,167				533,190				951,918
Costs and expenses:
Natural gas and liquids			145,001				313,763				409,152				936,313
Plant operating			14,762				16,652				42,713				46,418
General and administrative			6,028				(5,380	)			19,298				3,283
Depreciation and amortization			21,743				19,064				64,111				56,597
Total costs and expenses			187,534				344,099				535,274				1,042,611
Segment income (loss)		$	17,826			$	211,068			$	(2,084	)		$	(90,693	)
Appalachia
Revenue:
Natural gas and liquids		$	2			$	1,118			$	587			$	3,201
Transportation, compression and other fees – affiliates			380				11,916				16,877				32,496
Transportation, compression and other fees – third parties			1,087				384				1,930				952
Equity income in joint venture			1,430				—				2,140				—
Gain (loss) on asset sale			(994	)			—				108,947				—
Other income, net			91				73				230				273
Total revenue and other income, net			1,996				13,491				130,711				36,922
Costs and expenses:
Natural gas and liquids			(11	)			552				259				1,539
Transportation and compression			134				2,883				6,256				7,842
General and administrative			1,363				1,361				3,337				4,368
Depreciation and amortization			153				1,677				3,452				4,603
Total costs and expenses			1,639				6,473				13,304				18,352
Segment profit		$	357			$	7,018			$	117,407			$	18,570
Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent		$	17,826			$	211,068			$	(2,084	)		$	(90,693	)
Appalachia			357				7,018				117,407				18,570
Total segment income (loss)			18,183				218,086				115,323				(72,123	)
Corporate general and administrative expenses			(1,363	)			(1,362	)			(3,336	)			(4,368	)
Interest expense(2)			(28,320	)			(22,098	)			(75,820	)			(62,663	)
Other loss, net			(823	)			—				(823	)			—
Income (loss) from continuing operations			(12,323	)			194,626				35,344				(139,154	)
Income from discontinued operations			—				6,538				62,495				21,029
Net income (loss)		$	(12,323	)		$	201,164			$	97,839			$	(118,125	)
Capital Expenditures:
Mid-Continent		$	7,082			$	66,080			$	127,873			$	185,236
Appalachia			34				15,634				9,737				38,532
		$	7,116			$	81,714			$	137,610			$	223,768

 

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SEPTEMBER 30, 2009

(Unaudited)

 

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

(2)	The Partnership notes that interest expense has not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

 

Balance Sheet		September 30, 2009			December 31, 2008(1)
Total assets:
Mid-Continent		$	1,960,972		$	2,018,684
Appalachia			144,818			114,166
Discontinued operations			—			255,606
Corporate other			33,771			24,740
		$	2,139,561		$	2,413,196

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

The following tables summarize the Partnership’s total revenues by product or service for the periods indicated (in thousands):

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008(1)			2009			2008(1)
Natural gas and liquids:
Natural gas		$	62,545		$	152,127		$	197,043		$	474,808
NGLs			109,033			219,486			273,555			629,212
Condensate			10,850			15,748			20,183			50,751
Other (2)			12,012			9,378			35,697			31,917
Total		$	194,440		$	396,739		$	526,478		$	1,186,688
Transportation, compression and other fees:
Affiliates		$	380		$	11,916		$	16,877			32,496
Third Parties			4,719			6,125			12,574			16,792
Total		$	5,099		$	18,041		$	29,451		$	49,288

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

(2)	Includes treatment, processing, and other revenue associated with the products noted.

NOTE 18 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Partnership’s term loan and revolving credit facility is guaranteed by its wholly-owned subsidiaries. The guarantees are full, unconditional, joint and several. The Partnership’s consolidated financial statements as of September 30, 2009 and December 31, 2008 and for the three and nine months ended September 30, 2009 and 2008 include the financial statements of Chaney Dell LLC and Midkiff/Benedum, entities in which the Partnership has 95% ownership interests (see Note 2). The Partnership’s consolidated financial statements also include its 49% ownership interest in Laurel Mountain, which the Partnership recognizes as a long-term investment on its consolidated balance sheet and equity income on its consolidated statements of operations under the equity method of accounting (see Note 3). Under the terms of the term loan and revolving credit facility, Chaney Dell LLC and Midkiff/Benedum LLC are non-guarantor subsidiaries as they are not wholly-owned by the Partnership. The following supplemental condensed consolidating financial information reflects the Partnership’s stand-alone accounts, the combined accounts of the guarantor

 

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(Unaudited)

 

subsidiaries, the combined accounts of the non-guarantor subsidiaries, the consolidating adjustments and eliminations and the Partnership’s consolidated accounts as of September 30, 2009 and December 31, 2008 and for the three and nine months ended September 30, 2009 and 2008. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting (in thousands):

 

Balance Sheet		September 30, 2009
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries			Consolidating Adjustments				Consolidated
Assets
Cash and cash equivalents		$	7			$	5,254			$	—		$	—			$	5,261
Accounts receivable – affiliates			—				—				—			—				—
Current portion of derivative asset			—				4,514				—			—				4,514
Other current assets			—				33,012				53,410			—				86,422
Total current assets			7				42,780				53,410			—				96,197
Property, plant and equipment, net			—				596,338				1,101,888			—				1,698,226
Notes receivable			—				—				1,852,928			(1,852,928	)			—
Equity investments			570,545				230,753				—			(801,298	)			—
Investment in joint venture			—				133,740				—			—				133,740
Intangible assets, net			—				19,223				155,257			—				174,480
Long-term derivative asset			—				1,980				—			—				1,980
Other assets, net			28,661				5,071				1,206			—				34,938
		$	599,213			$	1,029,885			$	3,164,689		$	(2,654,226	)		$	2,139,561
Liabilities and Partners’ Capital (Deficit)
Accounts payable – affiliates		$	(1,404,459	)		$	1,288,995			$	116,262		$	—			$	798
Current portion of derivative liability			—				41,019				—			—				41,019
Other current liabilities			12,288				29,216				55,152			—				96,656
Total current liabilities			(1,392,171	)			1,359,230				171,414			—				138,473
Long-term derivative liability			—				9,256				—			—				9,256
Long-term debt, less current portion			1,243,050				—				—			—				1,243,050
Other long-term liability			—				448				—			—				448
Partners’ capital (deficit)			748,334				(339,049	)			2,993,275			(2,654,226	)			748,334
		$	599,213			$	1,029,885			$	3,164,689		$	(2,654,226	)		$	2,139,561

 

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(Unaudited)

 

Balance Sheet		December 31, 2008(1)
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Assets
Cash and cash equivalents		$	7			$	1,438			$	—			$	—			$	1,445
Accounts receivable – affiliates			1,444,812				—				—				(1,444,275	)			537
Current portion of derivative asset			—				44,961				—				—				44,961
Current assets – discontinued operations			—				13,441				—				—				13,441
Other current assets			—				37,019				73,977				—				110,996
Total current assets			1,444,819				96,859				73,977				(1,444,275	)			171,380
Property, plant and equipment, net			—				681,497				1,099,514				—				1,781,011
Notes receivable			—				—				1,852,928				(1,852,928	)			—
Equity investments			709,981				194,291				—				(904,272	)			—
Intangible assets, net			—				21,063				172,584				—				193,647
Long-term assets – discontinued operations			—				242,165				—				—				242,165
Other assets, net			23,676				1,135				182				—				24,993
		$	2,178,476			$	1,237,010			$	3,199,185			$	(4,201,475	)		$	2,413,196
Liabilities and Partners’ Capital (Deficit)
Accounts payable – affiliates		$	—			$	1,362,256			$	82,019			$	(1,444,275	)		$	—
Current portion of derivative liability			—				60,396				—				—				60,396
Current liabilities – discontinued operations			—				10,572				—				—				10,572
Other current liabilities			1,870				56,105				91,251				—				149,226
Total current liabilities			1,870				1,489,329				173,270				(1,444,275	)			220,194
Long-term derivative liability			—				48,159				—				—				48,159
Long-term debt, less current portion			1,493,427				—				—				—				1,493,427
Other long-term liability			—				574				—				—				574
Partners’ capital (deficit)			683,179				(301,052	)			3,025,915				(2,757,200	)			650,842
		$	2,178,476			$	1,237,010			$	3,199,185			$	(4,201,475	)		$	2,413,196
Statement of Operations		Three Months Ended September 30, 2009(1)
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Total revenue and other income (loss), net		$	—			$	74,173			$	148,801			$	(16,441	)		$	206,533
Total costs and expenses			(28,291	)			(81,733	)			(125,273	)			16,441				(218,856	)
Equity income in subsidiaries			69,799				24,084				—				(93,883	)			—
Income (loss) from continuing operations			41,508				16,524				23,528				(93,883	)			(12,323	)
Net income (loss)		$	41,508			$	16,524			$	23,528			$	(93,883	)		$	(12,323	)
Statement of Operations		Three Months Ended September 30, 2008(1)
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Total revenue and other income (loss), net		$	—			$	265,604			$	303,054			$	—			$	568,658
Total costs and expenses			(21,846	)			(116,111	)			(236,075	)			—				(374,032	)
Equity income in subsidiaries			220,823				67,383				—				(288,206	)			—
Income from continuing operations			198,977				216,876				66,979				(288,206	)			194,626
Income from discontinued operations			—				6,538				—				—				6,538
Net income		$	198,977			$	223,414			$	66,979			$	(288,206	)		$	201,164

 

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(Unaudited)

 

Statement of Operations		Nine Months Ended September 30, 2009
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Total revenue and other income (loss), net		$	—			$	291,097			$	420,518			$	(48,537	)		$	663,078
Total costs and expenses			(75,820	)			(241,857	)			(358,594	)			48,537				(627,734	)
Equity income in subsidiaries			172,996				63,338				—				(236,334	)			—
Income from continuing operations			97,176				112,578				61,924				(236,334	)			35,344
Income from discontinued operations			—				62,495				—				—				62,495
Net income		$	97,176			$	175,073			$	61,924			$	(236,334	)		$	97,839

 

Statement of Operations		Nine Months Ended September 30, 2008(1)
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Total revenue and other income (loss), net		$	—			$	106,594			$	882,246			$	—			$	988,840
Total costs and expenses			(61,612	)			(392,775	)			(673,607	)			—				(1,127,994	)
Equity income (loss) in subsidiaries			(63,409	)			209,536				—				(146,127	)			—
Income (loss) from continuing operations			(125,021	)			(76,645	)			208,639				(146,127	)			(139,154	)
Income from discontinued operations			—				21,029				—				—				21,029
Net income (loss)		$	(125,021	)		$	(55,616	)		$	208,639			$	(146,127	)		$	(118,125	)

 

Statement of Cash Flows		Nine Months Ended September 30, 2009(1)
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Cashflows from operating activities:
Net income		$	97,176			$	175,073			$	61,924			$	(236,334	)		$	97,839
Less: income from discontinued operations			—				62,495				—				—				62,495
Net income from continuing operations			97,176				112,578				61,924				(236,334	)			35,344
Adjustments to reconcile net income from continuing operations to net cash provided by (used in) operating activities:
Depreciation and amortization			—				22,588				44,975				—				67,563
Non-cash loss on derivative value, net			—				23,989				—				—				23,989
Equity income in joint venture			—				(2,140	)			—				—				(2,140	)
Gain on asset sales			—				(111,440	)			—				—				(111,440	)
Distributions received from joint venture			—				1,657				—				—				1,657
Non-cash compensation expense			497				—				—				—				497
Amortization of deferred financing costs			6,449				—				—				—				6,449
Net distributions to non-controlling interests			—				—				7				—				7
Changes in assets and liabilities net of effects of acquisitions			62,906				(12,525	)			1,928				(39,681	)			12,628
Net cash provided by (used in) continuing operations			167,028				34,707				108,834				(276,015	)			34,554
Net cash provided by discontinued operations			—				16,935				—				—				16,935
Net cash provided by (used in) operating activities			167,028				51,642				108,834				(276,015	)			51,489
Net cash provided by (used in) continuing investing activities			139,436				(20,420	)			(47,848	)			(102,974	)			(31,806	)
Net cash provided by discontinued investing activities			—				290,594				—				—				290,594
Net cash provided by (used in) investing activities			139,436				270,174				(47,848	)			(102,974	)			258,788
Net cash provided by (used in) financing activities			(306,464	)			(318,000	)			(60,986	)			378,989				(306,461	)
Net change in cash and cash equivalents			—				3,816				—				—				3,816
Cash and cash equivalents, beginning of period			7				1,438				—				—				1,445
Cash and cash equivalents, end of period		$	7			$	5,254			$	—			$	—			$	5,261

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

SEPTEMBER 30, 2009

(Unaudited)

 

Statement of Cash Flows		Nine Months Ended September 30, 2008(1)
		Parent				Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Cashflows from operating activities:
Net income (loss)		$	(125,021	)		$	(55,616	)		$	208,639			$	(146,127	)		$	(118,125	)
Less: income from discontinued operations			—				21,029				—				—				21,029
Net income (loss) from continuing operations			(125,021	)			(76,645	)			208,639				(146,127	)			(139,154	)
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by (used in) operating activities:
Depreciation and amortization			—				18,035				43,165				—				61,200
Non-cash gain on derivative value, net			—				(57,009	)			—				—				(57,009	)
Non-cash compensation income			(14,274	)			—				—				—				(14,274	)
Amortization of deferred financing costs			3,650				—				—				—				3,650
Net distributions to non- controlling interests			—				—				(7,905	)			—				(7,905	)
Changes in assets and liabilities net of effects of acquisitions			(397,794	)			334,344				68,295				47,657				52,502
Net cash provided by (used in) continuing operations			(533,439	)			218,725				312,194				(98,470	)			(100,990	)
Net cash provided by discontinued operations			—				37,474				—				—				37,474
Net cash provided by (used in) operating activities			(533,439	)			256,199				312,194				(98,470	)			(63,516	)
Net cash provided by (used in) continuing investing activities			224,656				12,526				(25,831	)			(402,595	)			(191,244	)
Net cash used in discontinued investing activities			—				(22,626	)			—				—				(22,626	)
Net cash provided by (used in) investing activities			224,656				(10,100	)			(25,831	)			(402,595	)			(213,870	)
Net cash provided by (used in) financing activities			308,783				(196,653	)			(304,412	)			501,065				308,783
Net change in cash and cash equivalents			—				49,446				(18,049	)			—				31,397
Cash and cash equivalents, beginning of period			7				(5,715	)			18,049				—				12,341
Cash and cash equivalents, end of period		$	7			$	43,731			$	—			$	—			$	43,738

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

NOTE 19 – SUBSEQUENT EVENTS

On November 2, 2009, the Partnership’s agreement with Pioneer, whereby Pioneer had an option to purchase up to an additional 22.0% interest in the Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 2).

 

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ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption “Risk Factors”, in our annual report on Form 10-K for 2008. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

General

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report.

Overview

We are a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol “APL”. Our principal business objective is to generate cash for distribution to our unitholders. We are a leading provider of natural gas gathering services in the Anadarko and Permian Basins and the Golden Trend in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, we are a leading provider of natural gas processing and treatment services in Oklahoma and Texas. Our business is conducted in the midstream segment of the natural gas industry through two reportable segments: our Mid-Continent operations and our Appalachian operations.

As of September 30, 2009, through our Mid-Continent operations, we own and operate:

 

•

eight active natural gas processing plants with aggregate capacity of approximately 810 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

 

•

8,750 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to our natural gas processing and treating plants or third party pipelines.

As of September 30, 2009, our Appalachia operations are conducted principally through our 49% ownership interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which owns and operates a 1,770 mile natural gas gathering system in the Appalachia Basin located in eastern Ohio, western New York, and western Pennsylvania. We also own a 65 mile natural gas gathering system in northeastern Tennessee. Laurel Mountain gathers the majority of the natural gas from wells operated by Atlas Energy, Inc. and its subsidiaries (“Atlas Energy”), a publicly-traded company (NASDAQ: ATLS) which owns a 64.4% ownership interest in AHD and 1,112,000 of our common limited partnership units, representing a 2.2% ownership interest in us, at September 30, 2009.

Recent Events

On July 13, 2009, we sold a natural gas processing facility and a one-third undivided interest in other associated assets located in

 

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our Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse us for its proportionate share of the operating expenses. We will continue to operate the facility. We used the proceeds from this transaction to reduce outstanding borrowings under our senior secured credit facility. We recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on our consolidated statements of operations.

Subsequent Events

On November 2, 2009, our agreement with Pioneer Natural Resources Company (“Pioneer”), whereby Pioneer had an option to purchase up to an additional 22.0% interest in the Mid-Continent’s Midkiff/Benedum system, expired without Pioneer exercising its option (see Note 2 under Item 1, “Financial Statements”).

Contractual Revenue Arrangements

Our principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables that affect our revenue are:

 

•

the volumes of natural gas we gather, transport and process which, in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and

 

•

the transportation and processing fees we receive which, in turn, depend upon the price of the natural gas and NGLs we transport and process, which itself is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States.

Our revenue consists of the fees earned from our transmission, gathering and processing operations. Under certain agreements, we purchase natural gas from producers and move it into receipt points on our pipeline systems, and then sell the natural gas, or produced NGLs, if any, off of delivery points on our systems. Under other agreements, we transport natural gas across our 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 our gathering and processing operations, we enter into the following types of contractual relationships with our producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. Our revenue is a function of the volume of natural gas that we gather and process and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for us to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs we gather and process, with the remainder being remitted to the producer. In this situation, we and the producer are directly dependent on the volume of the commodity and its value; we own a percentage of that commodity and are directly subject to its market value.

Keep-Whole Contracts. These contracts require us, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, we bear 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 we 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 on these systems and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of our keep-whole contracts is minimized.

 

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Recent Trends and Uncertainties

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

We face competition for natural gas transportation and in obtaining natural gas supplies for our processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas-gathering facilities and gas-processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of high-quality customer relationships. Many of our competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies in our regions of operations.

As a result of our POP and keep-whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas and NGLs. We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the recent past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of our assets and operations from such price risks. We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices. A 10% change in the average price of NGLs, natural gas and condensate we process and sell, based on estimated unhedged market prices of $0.80 per gallon, $5.61 per mmbtu and $72.03 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin for the twelve-month period ending September 30, 2010 by approximately $24.3 million.

Currently, there is an unprecedented level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us. These risks include the availability and costs associated with our borrowing capabilities and raising additional capital, and an increase in the volatility of the price of our common units. While we have no definitive plans to access the capital markets, should we decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

 

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Results of Operations

The following table illustrates selected volumetric information related to our reportable segments for the periods indicated:

 

		Three Months Ended September 30,				Nine Months Ended September 30,
		2009		2008		2009		2008
Operating data(1):
Appalachia:
Average throughput volume – mcfd(2)		105,989		91,829		104,009		84,007
Mid-Continent:
Velma system:
Gathered gas volume – mcfd		81,562		64,386		75,919		64,103
Processed gas volume – mcfd		78,714		60,902		73,351		60,972
Residue gas volume – mcfd		62,219		48,300		57,959		48,158
NGL volume – bpd		8,922		6,595		8,158		6,758
Condensate volume – bpd		389		308		383		286
Elk City/Sweetwater system:
Gathered gas volume – mcfd		211,287		279,145		228,630		292,307
Processed gas volume – mcfd		200,182		243,409		223,438		236,520
Residue gas volume – mcfd		181,011		219,945		203,034		213,668
NGL volume – bpd		10,792		11,486		11,361		10,874
Condensate volume – bpd		260		251		374		299
Chaney Dell system:
Gathered gas volume – mcfd		268,723		300,467		282,756		278,906
Processed gas volume – mcfd		202,516		234,529		216,407		246,365
Residue gas volume – mcfd		218,420		250,994		238,167		238,264
NGL volume – bpd		13,376		14,128		13,574		13,299
Condensate volume – bpd		750		759		861		774
Midkiff/Benedum system:
Gathered gas volume – mcfd		166,423		143,224		160,631		145,300
Processed gas volume – mcfd		152,314		136,656		149,516		138,178
Residue gas volume – mcfd		104,895		84,372		103,078		92,352
NGL volume – bpd		19,926		18,920		21,006		20,029
Condensate volume – bpd		1,942		1,573		1,426		1,288

 

(1)	“Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day.

(2)	Includes 100% of the throughput volume of Laurel Mountain, a joint venture in which we have a 49% ownership interest, beginning on May 31, 2009.

Financial Presentation

On May 4, 2009, we completed the sale of our NOARK gas gathering and interstate pipeline system. As such, we have adjusted the prior period consolidated financial information presented to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenue. Natural gas and liquids revenue was $194.4 million for the three months ended September 30, 2009, a decrease of $202.3 million from $396.7 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from the Chaney Dell system of $78.3 million, the Midkiff/Benedum system of $47.2 million, the Elk City/Sweetwater system of $45.3 million and the Velma system of $30.3 million, which were all impacted by lower average commodity prices in comparison to the prior year comparable period. The Velma system had average processed natural gas volume of 78.7 MMcfd for the three months ended September 30, 2009, an increase of 29.2% from the comparable prior year period. The Midkiff/Benedum system had average processed natural gas volume of 152.3 MMcfd for the three months ended September 30, 2009, an increase of 11.5% compared to the comparable prior year period. Processed natural gas volume on the Chaney Dell system averaged 202.5 MMcfd for the three months ended September 30, 2009, a decrease of 13.6% compared to the comparable prior year period. Processed natural gas volume on the Elk City/Sweetwater system averaged 200.2 MMcfd for the three months ended September 30, 2009, a decrease of 17.8% from the comparable prior year period. We enter into derivative instruments to hedge our

 

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forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “Quantitative and Qualitative Discussion About Market Risk”.

Transportation, compression and other fee revenue decreased to $5.1 million for the three months ended September 30, 2009 compared with $18.0 million for the comparable prior year period. This $12.9 million decrease was primarily due to a $10.8 million decrease from the Appalachia system and a $1.5 million decrease from the Chaney Dell system. The decrease from the Appalachia system was due to our contribution of the system to Laurel Mountain, a joint venture in which we have a 49% ownership interest, in May 2009, after which we have recognized our ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations. The decrease from the Chaney Dell system was due to lower fee-based volumes.

Equity income of $1.4 million for the three months ended September 30, 2009 represents our ownership interest in the net income of Laurel Mountain, a joint venture in which we own a 49% interest.

Gain on asset sales of $1.5 million for the three months ended September 30, 2009 represents a $2.5 million gain recognized on our sale of the natural gas processing facility (see “—Recent Events”), partially offset by a $1.0 million adjustment to the gain on the sale of the 51% ownership interest in our Appalachia natural gas gathering system to Laurel Mountain.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was a gain of $4.1 million for the three months ended September 30, 2009, which represents an unfavorable movement of $149.8 million from $153.9 million of income for the prior year comparable period. This unfavorable movement was due primarily to a $223.0 million unfavorable movement in non-cash mark-to-market adjustments on derivatives and a $5.2 million unfavorable movement related to cash settlements on non-qualified derivatives, partially offset by the absence in the current year period of $70.3 million of net cash derivative expense related to the early termination of a portion of our derivative contracts (see Note 12 to the consolidated financial statements in Item 1, “Financial Statements”) and a favorable movement of $9.0 million for non-cash derivative gains related to the early termination of a portion of our derivative contracts. The $223.0 million unfavorable movement in non-cash mark-to-market adjustments on derivatives was due principally to the recognition of a $235.0 million gain during the three months ended September 30, 2008, which was due to a decrease in forward crude oil market prices from June 30, 2008 to September 30, 2008 and their favorable mark-to-market impact on certain non-qualified derivative contracts we had for production volumes in future periods. Average forward crude oil prices, which were the basis for adjusting the fair value of our crude oil derivative contracts, at September 30, 2008 were $102.64 per barrel, a decrease of $37.48 per barrel from average forward crude oil market prices at June 30, 2008 of $140.12 per barrel. We enter into derivative instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “Quantitative and Qualitative Discussion About Market Risk”.

Costs and Expenses. Natural gas and liquids cost of goods sold of $145.0 million for the three months ended September 30, 2009 represented a decrease of $169.3 million from the prior year comparable period due primarily to a decrease in average commodity prices in comparison to the prior year comparable period. Plant operating expenses of $14.8 million for the three months ended September 30, 2009 represented a decrease of $1.2 million from the prior year comparable period due primarily to a $1.5 million decrease associated with the Chaney Dell system resulting from lower operating and maintenance costs. Transportation and compression expenses decreased to $0.1 million for the three months ended September 30, 2009 compared with $2.9 million for the prior year comparable period due to our contribution of the Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, increased $11.5 million to $8.8 million for the three months ended September 30, 2009 compared with income of $2.7 million for the prior year comparable period. The increase

 

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was primarily due to a $13.3 million mark-to-market gain recognized during the three months ended September 30, 2008 for certain common unit awards that were based on the financial performance of certain assets during 2008. The mark-to-market gain was the result of a significant change in our common unit market price at September 30, 2008 when compared with the June 30, 2008 price, which was utilized in the estimate of the non-cash compensation expense for these awards.

Depreciation and amortization increased to $21.9 million for the three months ended September 30, 2009 compared with $20.7 million for the three months ended September 30, 2008 due primarily to our expansion capital expenditures incurred subsequent to September 30, 2008.

Interest expense increased to $28.3 million for the three months ended September 30, 2009 as compared with $22.1 million for the comparable prior year period. This $6.2 million increase was primarily due to a $4.2 million increase in interest expense associated with outstanding borrowings on our revolving credit facility, (see “—Term Loan and Revolving Credit Facility”), $1.2 million of lower interest capitalized as a component of capital expenditures and a $1.0 million increase in interest expense associated with our senior secured term loan.

Income from discontinued operations, which consists of amounts associated with the NOARK gas gathering and interstate pipeline system we sold in May 2009, was $6.5 million for the three months ended September 30, 2008.

Income attributable to non-controlling interests was a net income reduction of $1.0 million for the three months ended September 30, 2009 compared with $2.6 million for the comparable prior year period. This decrease was primarily due to lower net income for the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems. The income attributable to non-controlling interests represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenue. Natural gas and liquids revenue was $526.5 million for the nine months ended September 30, 2009, a decrease of $660.2 million from $1,186.7 million for the comparable prior year period. The decrease was primarily attributable to decreases in production revenue from the Chaney Dell system of $246.4 million, the Midkiff/Benedum system of $175.1 million, the Elk City/Sweetwater system of $127.6 million and the Velma system of $108.4 million, which were all impacted by lower average commodity prices in comparison to the prior year comparable period. Processed natural gas volume averaged 73.4 MMcfd on the Velma system for the nine months ended September 30, 2009, an increase of 20.3% from the comparable prior year period. The Midkiff/Benedum system had average processed natural gas volume of 149.5 MMcfd for the nine months ended September 30, 2009, an increase of 8.2% from the comparable prior year period. Processed natural gas volume on the Elk City/Sweetwater system averaged 223.4 MMcfd for the nine months ended September 30, 2009, a decrease of 5.5% from the comparable prior year period. However, NGL production volume for the Elk City/Sweetwater system was an average of 11,361 bpd, an increase of 4.5% from the comparable prior year period, representing an increase in plant production efficiency. Processed natural gas volume on the Chaney Dell system averaged 216.4 MMcfd for the nine months ended September 30, 2009, a decrease of 12.2% compared to 246.4 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 2.1% from the comparable prior year period to 13,574 bpd for the nine months ended September 30, 2009, representing an increase in plant production efficiency. We enter into derivative instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “Quantitative and Qualitative Discussion About Market Risk”.

Transportation, compression and other fee revenue decreased to $29.5 million for the nine months ended September 30, 2009 compared with $49.3 million for the comparable prior year period. This $19.8 million decrease was primarily due to a $14.6 million decrease from the Appalachia system and a $4.6 million decrease from the Chaney Dell system. The decrease from the Appalachia

 

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system was due to our contribution of the system to Laurel Mountain, a joint venture in which we have a 49% ownership interest, in May 2009, after which we have recognized our ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations. The decrease from the Chaney Dell system was due to lower fee-based volumes.

Equity income of $2.1 million for the nine months ended September 30, 2009 represents our ownership interest in the net income of Laurel Mountain, a joint venture in which we own a 49% interest, for the period from formation on May 31, 2009 through September 30, 2009.

Gain on asset sales of $111.4 million for the nine months ended September 30, 2009 represents the gain recognized on our sale of a 51% ownership interest in our Appalachia natural gas gathering system of $108.9 million and the $2.5 million gain recognized on our sale of the natural gas processing facility (see “—Recent Events”).

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, was a loss of $6.4 million for the nine months ended September 30, 2009, which represents a favorable movement of $240.7 million from the comparable prior year period loss of $247.1 million. This favorable movement was due primarily to the absence in the current year period of $186.1 million of net cash derivative expense related to the early termination of a portion of our derivative contracts, (see Note 12 to the consolidated financial statements in Item 1, “Financial Statements”), a $74.6 million favorable movement in non-cash derivative gains related to the early termination of a portion of our derivative contracts, and a $28.3 million favorable movement related to cash settlements on non-qualified derivatives, partially offset by an unfavorable movement of $43.0 million in non-cash mark-to-market adjustments on derivatives. We enter into derivative instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 3, “Quantitative and Qualitative Discussion About Market Risk”.

Costs and Expenses. Natural gas and liquids cost of goods sold of $409.4 million for the nine months ended September 30, 2009 represented a decrease of $528.5 million from the prior year comparable period due primarily to a decrease in average commodity prices in comparison to the prior year period. Plant operating expenses of $42.7 million for the nine months ended September 30, 2009 represented a decrease of $3.7 million from the prior year comparable period due primarily to a $1.9 million decrease associated with the Chaney Dell system and a $1.1 million decrease associated with the Midkiff/Benedum system resulting from lower operating and maintenance costs. Transportation and compression expenses decreased to $6.3 million for the nine months ended September 30, 2009 compared with $7.8 million for the prior year comparable period due to our contribution of the Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, increased $14.0 million to $26.0 million for the nine months ended September 30, 2009 compared with $12.0 million for the prior year comparable period. The increase was primarily related to a $14.8 million increase in non-cash compensation expense due to a $16.1 million net mark-to-market gain recognized during the nine months ended September 30, 2008 principally associated with the vesting of certain common unit awards that were based on the financial performance of certain assets during 2008. The mark-to-market gain was the result of a significant change in our common unit market price at September 30, 2008 when compared with the December 31, 2007 price, which was utilized in the estimate of the non-cash compensation expense for these awards. These common unit awards were issued during the nine months ended September 30, 2009.

Depreciation and amortization increased to $67.6 million for the nine months ended September 30, 2009 compared with $61.2 million for the nine months ended September 30, 2008 due primarily to our expansion capital expenditures incurred subsequent to September 30, 2008.

 

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Interest expense increased to $75.8 million for the nine months ended September 30, 2009 as compared with $62.7 million for the comparable prior year period. This $13.1 million increase was primarily due to a $8.9 million increase in interest expense related to our additional senior notes issued during June 2008 (see “—Senior Notes”), a $6.2 million increase in interest expense associated with outstanding borrowings on our revolving credit facility, and a $2.8 million increase in the amortization of deferred finance costs due principally to accelerated amortization associated with the retirement of a portion of our term loan with the proceeds from the sale of our NOARK system, partially offset by a $6.4 million decrease in interest expense associated with our senior secured term loan primarily due to the repayment of $370.1 million of indebtedness since September 2008 (see “—Term Loan and Revolving Credit Facility”) and lower unhedged interest rates.

Income from discontinued operations, which consists of amounts associated with the NOARK gas gathering and interstate pipeline system we sold in May 2009, was $62.5 million for the nine months ended September 30, 2009 compared with $21.0 million for the comparable prior year period. The increase was due to a $51.1 million gain recognized on the sale of the NOARK system, partially offset by a $9.6 million decrease in the operating results of the NOARK system due to its sale in May 2009.

Income attributable to non-controlling interests was a net income reduction of $2.1 million for the nine months ended September 30, 2009 compared with $7.8 million for the comparable prior year period. This decrease was primarily due to lower net income for the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect our acquisition of control of the respective systems. The income attributable to non-controlling interests represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Liquidity and Capital Resources

General

Our primary sources of liquidity are cash generated from operations and borrowings under our credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to our common unitholders and general partner. In general, we expect to fund:

 

•

cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

 

•

expansion capital expenditures and working capital deficits through the retention of cash and additional borrowings; and

 

•

debt principal payments through additional borrowings as they become due or by the issuance of additional limited partner units or asset sales.

At September 30, 2009, we had $315.0 million of outstanding borrowings under our $380.0 million senior secured credit facility and $9.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $55.9 million of remaining committed capacity under the credit facility, subject to covenant limitations (see “—Term Loan and Revolving Credit Facility”). We were in compliance with the credit facility’s covenants at September 30, 2009. At September 30, 2009, we had a working capital deficit of $42.3 million compared with a working capital deficit of $48.8 million at December 31, 2008. We believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we are subject to business, operational and other risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional limited partner units and sales of our assets.

 

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Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds from those markets has diminished significantly. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Net cash provided by operating activities of $51.5 million for the nine months ended September 30, 2009 represented an increase of $115.0 million from $63.5 million of net cash used in operating activities for the prior year comparable period. The increase was derived from a $175.4 million favorable movement in net earnings from continuing operations excluding non-cash charges, partially offset by a $39.9 million decrease in cash flows from working capital changes and a $20.5 million unfavorable movement in cash provided by discontinued operations. The increase in net earnings from continuing operations excluding non-cash charges was principally due to the absence in the current year period of $186.1 million of net cash derivative expense related to early termination of a portion of our derivative contracts (see Note 12 to the consolidated financial statements in Item 1, “Financial Statements”). Non-cash charges which impacted net earnings excluding non-cash charges include an $81.0 million increase in non-cash derivative losses, a $108.9 million decrease resulting from the gain on the sale of our Appalachia system assets to subsidiaries of The Williams Companies, Inc. to form the Laurel Mountain joint venture and a $2.5 million decrease resulting from the gain on the sale of a natural gas processing facility, partially offset by a $6.4 million increase in depreciation and amortization expense and a $14.8 million increase in non-cash compensation expense. The movement in non-cash derivative losses resulted from decreases in commodity prices during the respective periods presented and their unfavorable impact on the fair value of derivative contracts we have for future periods. The increase in depreciation and amortization principally resulted from depreciation associated with our expansion capital expenditures incurred subsequent to September 30, 2008. The increase in non-cash compensation was principally attributable to a $16.1 million net mark-to-market gain recognized during the prior year comparable period principally associated with the vesting of certain common unit awards that were based on the financial performance of certain assets during 2008. The mark-to-market gain was the result of a significant change in our common unit market price at September 30, 2008 when compared with the December 31, 2007 price, which was utilized in the estimate of the non-cash compensation expense for these awards.

Net cash provided by investing activities was $258.8 million for the nine months ended September 30, 2009, an increase of $472.7 million from $213.9 million of net cash used in investing activities for the prior year comparable period. This increase was principally due to a $313.2 million increase in cash provided by discontinued operations, the net proceeds of $110.4 million received from the sale of our Appalachian system assets and a natural gas processing facility and an $86.2 million decrease in capital expenditures, partially offset by a prior year receipt of a $30.2 million cash reimbursement for state sales tax paid on our prior year transaction to acquire the Chaney Dell and Midkiff/Benedum systems and a prior year period receipt of $1.3 million in connection with a post-closing purchase price adjustment of our 2007 acquisition of the Chaney Dell and Midkiff/Benedum. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash used in financing activities was $306.5 million for the nine months ended September 30, 2009, a decrease of $615.3 million from $308.8 million of net cash provided by financing activities for the comparable prior year period. This decrease was principally due to a decrease of $240.8 million of net proceeds from the issuance of our common units, the absence in the current period of $244.9 million of net proceeds from the issuance of 8.75% Senior Notes during June 2008 (see “—Senior Notes”), a $57.0 million net decrease in borrowings under our revolving credit facility, a $150.8 million increase in repayments of the outstanding principal balance on our senior secured term loan, a $15.0 million redemption of our outstanding Class A preferred units held by

 

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Sunlight Capital and our $15.0 million preferred unit investment in Atlas Pipeline Holdings II, LLC (see Note 7 under Item 1., “Financial Statements”), partially offset by a $113.3 million decrease in cash distributions to common limited partners and the general partner.

Capital Requirements

Our operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. Our capital requirements consist primarily of:

 

•

maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

 

•

expansion capital expenditures to acquire complementary assets and to expand the capacity of our existing operations.

The following table summarizes maintenance and expansion capital expenditures related to continuing operations, excluding amounts paid for acquisitions, for the periods presented (in thousands):

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008(1)			2009			2008(1)
Maintenance capital expenditures		$	1,460		$	1,490		$	3,561		$	4,976
Expansion capital expenditures			5,656			80,224			134,049			218,792
Total		$	7,116		$	81,714		$	137,610		$	223,768

 

(1)	Restated to reflect amounts reclassified to discontinued operations due to our sale of our NOARK gas gathering and interstate pipeline system.

Expansion capital expenditures decreased to $5.7 million and $134.0 million for the three and nine months ended September 30, 2009, respectively, compared with $80.2 million and $218.8 million for the prior year comparable periods. The decrease was due principally to construction of a 60MMcfd expansion of our Sweetwater processing plant and the construction of the Madill to Velma pipeline during the prior year, decreases in capital expenditures related to the sale of the NOARK system and a 49% ownership interest in the Appalachia system, and other decreases in capital spending related to the expansion of our gathering systems. As of September 30, 2009, we are committed to expend approximately $17.8 million on pipeline extensions, compressor station upgrades and processing facility upgrades. Our senior secured credit facility (see “—Term Loan and Revolving Credit Facility”) generally limits our annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter.

Partnership Distributions

Our partnership agreement requires that we distribute 100% of available cash to our common unitholders and our general partner within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

 

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Our general partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to our common limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. During July 2007, our general partner, holder of all of our incentive distribution rights, agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to us after the general partner receives the initial $7.0 million per quarter of incentive distribution rights.

On May 29, 2009, we entered into an amendment to our senior secured credit facility (see “—Term Loan and Revolving Credit Facility”) which, among other changes, requires that we pay no cash distributions during the remainder of the year ended December 31, 2009 and allows us to pay cash distributions beginning January 1, 2010 if our senior secured leverage ratio is above certain thresholds and we have minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

Off Balance Sheet Arrangements

As of September 30, 2009, our off balance sheet arrangements are limited to our letters of credit outstanding of $9.1 million and our commitments to expend approximately $17.8 million on capital projects.

Common Equity Offerings

In August 2009, we sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. We also received a capital contribution from AHD of $0.4 million for AHD to maintain its 2.0% general partner interest in us. In addition, we issued warrants granting investors in our private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. We utilized the net proceeds from the common unit offering to repay a portion of our indebtedness under our senior secured term loan (see “—Term Loan and Revolving Credit Facility”), and we will make similar repayments with net proceeds from future exercises of the warrants.

The common units and warrants sold by us in the August 2009 private placement are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required us to (a) file a registration statement with the Securities and Exchange Commission for the privately placed common units and those underlying the warrants by September 21, 2009 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by November 18, 2009. We filed a registration statement with the Securities and Exchange Commission in satisfaction of the registration requirements of the registration rights agreement on September 3, 2009, and the registration statement was declared effective on October 14, 2009.

In June 2008, we sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, we sold 1,112,000 common units to Atlas Energy and 278,000 common units to AHD in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. We also received a capital contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in us. We utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements.

 

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Preferred Units

Class A Preferred Units

In January 2009, we and Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, agreed to amend certain terms of the preferred units certificate of designation for the then-outstanding 30,000 $1,000 par value 12.0% cumulative convertible Class A preferred units of limited partner interests (the “Class A Preferred Units”), which was initially entered into in March 2006. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, (b) established a new conversion commencement date on the outstanding Class A Preferred Units of April 1, 2009, (c) established Sunlight Capital’s new conversion option price of $22.00, enabling the Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of our common units, and (d) established a new price for our call redemption right of $27.25.

The amendment to the preferred units certificate of designation also required that we issue Sunlight Capital $15.0 million of our 8.125% senior unsecured notes due 2015 (see “—Senior Notes”) to redeem 10,000 Class A Preferred Units. Our management estimated that the fair value of the $15.0 million 8.125% senior unsecured notes issued to redeem the Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded senior notes. As such, we recorded the redemption by recognizing a $10.0 million reduction of Class A Preferred equity within Partners’ Capital, $15.0 million of additional long-term debt for the face value of the senior unsecured notes issued, and a $5.0 million discount on the issuance of the senior unsecured notes that will be presented as a reduction of long-term debt on our consolidated balance sheet. The discount recognized upon issuance of the senior unsecured notes will be amortized to interest expense in our consolidated statements of operations over the term of the notes based upon the effective interest rate method.

The amendment to the preferred units certificate of designation also required that (a) we redeem 10,000 of the Class A Preferred Units for cash at the liquidation value on April 1, 2009 and (b) that if Sunlight Capital made a conversion request of the remaining 10,000 Class A Preferred Units between April 1, 2009 and June 1, 2009, we had the option of redeeming the Class A Preferred Units for cash at the stipulated liquidation value or converting the Class A Preferred Units into our common limited partner units at the stipulated conversion price. If Sunlight Capital made a conversion request subsequent to June 1, 2009, 5,000 of the 10,000 Class A Preferred Units would have been required to be redeemed in cash, while we had the option of redeeming the remaining 5,000 Class A Preferred Units in cash or converting the preferred units into our common limited partner units. On April 1, 2009, we redeemed 10,000 of the Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $10.0 million, in accordance with the terms of the amended preferred units certificate of designation. On April 13, 2009, we converted 5,000 of the Class A Preferred Units into 1,465,653 common units in accordance with the terms of the amended preferred units certificate of designation. We reclassified $5.0 million from Class A preferred limited partner equity to common limited partner equity within partners’ capital when these preferred units were converted into common limited partner units. On May 5, 2009, we redeemed the remaining 5,000 Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $5.0 million, pursuant to the terms of the amended preferred units certificate of designation.

Class B Preferred Units

In December 2008, we sold 10,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “Class B Preferred Units”) to AHD for cash consideration of $1,000 per Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “Class B Preferred Units Certificate of Designation”). On March 30, 2009, AHD, pursuant to its right within the Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 Class B Preferred Units at Face Value. We used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. The Class B Preferred Units receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for our common units. The record

 

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date of determination for holders entitled to receive distributions of the Class B Preferred Units will be the same as the record date of determination for common unit holders entitled to receive quarterly distributions. Additionally, on March 30, 2009, we and AHD agreed to amend the terms of the Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the Class B Preferred Units are not convertible into our common units. The amended Class B Preferred Units Certificate of Designation also gives us the right at any time to redeem some or all of the outstanding Class B Preferred Units for cash at an amount equal to the Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 Class B Preferred Units or b) the number of remaining outstanding Class B Preferred Units.

The cumulative sale of the Class B Preferred Units to AHD is exempt from the registration requirements of the Securities Act of 1933. Dividends paid on the Class B Preferred Units and the premium paid upon the redemption of the Class B Preferred Units, if any, will be recognized as a reduction of our net income (loss) in determining net income (loss) attributable to common unitholders and the general partner. The Class B Preferred Units are reflected on our consolidated balance sheet as Class B preferred equity within partners’ capital.

Term Loan and Revolving Credit Facility

At September 30, 2009, we 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 the credit facility bear interest, at our 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 revolving credit facility borrowings at September 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding 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 our consolidated balance sheet.

On May 29, 2009, we entered into an amendment to our 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 minimum ratio of interest coverage (as defined in the credit agreement) that the credit facility requires us 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 us to maintain;

 

•

required that we pay no cash distributions during the remainder of the year ended December 31, 2009 and allows us to pay cash distributions beginning January 1, 2010 if our senior secured leverage ratio is less than 2.75x and we have minimum liquidity (as defined in the credit agreement) of at least $50.0 million;

 

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•

generally limits our annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;

 

•

permitted us 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 our leverage ratio.

In June 2008, we entered into an amendment to our credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to our early termination of certain derivative contracts (see Note 11 to the consolidated financial statements under Item 1, “Financial Statements”) in calculating our Consolidated EBITDA. Pursuant to this amendment, in June 2008, we repaid $122.8 million of our outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from our issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “—Senior Notes”). Additionally, pursuant to this amendment, in June 2008 our lenders increased their commitments for our revolving credit facility by $80.0 million to $380.0 million.

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

The events which constitute an event of default for our 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 us in excess of a specified amount, and a change of control of our General Partner. The credit facility requires us to maintain the following ratios:

 

Fiscal quarter ending:		Maximum Leverage Ratio		Maximum Senior Secured Leverage Ratio		Minimum Interest Coverage 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

 

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

Senior Notes

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

In January 2009, we issued Sunlight Capital $15.0 million of our 8.125% Senior Notes to redeem 10,000 Class A Preferred Units (see “—Preferred Units”). Our management 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, we recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on our consolidated balance sheet. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense in our consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

Indentures governing the Senior Notes in the aggregate contain covenants, including limitations of our 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. We are in compliance with these covenants as of September 30, 2009.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period.

 

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Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. A discussion of our significant accounting policies we have adopted and followed in the preparation of our consolidated financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2008, and there have been no material changes to these policies through September 30, 2009.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

We use a fair value methodology to value the assets and liabilities for our respective outstanding derivative contracts (see Note 11 to the consolidated financial statements under Item 1, “Financial Statements”). At September 30, 2009, all of our derivative contracts are defined as Level 2, with the exception of our NGL fixed price swaps and NGL options. Our Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. Our interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Valuations for our NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations and therefore are defined as Level 3. Valuations for our NGL options are based on forward price curves developed by the related financial institutions, and therefore are defined as Level 3.

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. We adopted the requirements on September 30, 2009 and it did not have a material impact on our financial position, results of operations or related disclosures.

 

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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. We adopted the requirements of FASB Update 2009-04 on August 1, 2009 and it did not have a material impact on our 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. We adopted the requirements of Update 2009-01 to our financial statements on September 30, 2009 and it did not have a material impact on our 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. We adopted the requirements of this standard on June 30, 2009 and it did not have a material impact to our financial position or results of operations or related disclosures. The adoption of these provisions does not change our 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. We adopted the requirements of ASC 820-10-65-4 on April 1, 2009 and its adoption did not have a material impact on our 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

 

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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. We adopted these requirements on April 1, 2009 and its adoption did not have a material impact on our 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. We adopted these requirements on April 1, 2009 and its adoption did not have a material impact on our 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 us). We adopted the requirements on January 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

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. We adopted the requirements on January 1, 2009 and its adoption did not have a material impact on our 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. We adopted the requirements of ASC 350-30-65-1 on January 1, 2009 and its adoption did not have a material impact on our 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

 

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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. Our adoption of ASC 260-10-55-103 on January 1, 2009 impacted our presentation of net income (loss) per common limited partner unit as we 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” in Note 2 to the consolidated financial statements under Item 1, “Financial Statements”). We adopted the requirements of ASC 260-10-55-103 on January 1, 2009 and its adoption did not have a material impact on our 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. We 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 our financial position or results of operations (see Note 11 to the consolidated financial statements under Item 1, “Financial Statements”).

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. We adopted the requirements of ASC 810-10-65-1 on January 1, 2009 and adjusted our presentation of our 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. Changes subsequent to that date are to be recognized in earnings, not goodwill. 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. We adopted these requirements on January 1, 2009 and it did not have a material impact on our 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.

 

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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. We will apply these requirements upon its adoption on January 1, 2010 and we do not expect it to have a material impact to our 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 us). We will apply these requirements upon its adoption on January 1, 2010 and we do not expect it to have a material impact to our financial position or results of operations or related disclosures.

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than trading.

General

All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative instruments. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on September 30, 2009. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties to our commodity and interest-rate derivative contracts are banking institutions who also participate in our revolving credit facility. The creditworthiness of our counterparties is constantly monitored, and we are not aware of any inability on the part of our counterparties to perform under our contracts.

Interest Rate Risk. At September 30, 2009, we had a $380.0 million senior secured revolving credit facility ($315.0 million outstanding). We also had $433.5 million outstanding under our senior secured term loan at September 30, 2009. Borrowings under the credit facility bear interest, at our 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). On May 29, 2009, we entered into an amendment to our senior secured revolving credit facility agreement which, among other changes, set a floor for the LIBOR interest rate of 2.0% per annum. The weighted average interest rate for the revolving credit facility borrowings was 6.8% at September 30, 2009, and the weighted average interest rate for the term loan borrowings was 6.8% at September 30, 2009.

 

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At September 30, 2009, we have interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, we will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of our revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreements are in effect as of September 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, we discontinued hedge accounting for our interest rate derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives will be recognized immediately within other income (loss), net in our consolidated statements of operations.

Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our annual interest expense by $4.5 million.

Commodity Price Risk. We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. A 10% change in the average price of NGLs, natural gas and condensate we process and sell, based on estimated unhedged market prices of $0.80 per gallon, $5.61 per mmbtu and $72.03 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin for the twelve-month period ending September 30, 2010 by approximately $24.3 million.

We use a number of different derivative instruments, principally swaps and options, in connection with our commodity price and interest rate risk management activities. We enter into financial swap and option instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. We also enter into financial swap instruments to hedge certain portions of our 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 and condensate are sold or interest payments on the underlying debt instrument are due. Under swap agreements, we receive or pay a fixed price and receive or remit 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 the obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant contract period.

We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching derivative contracts to the forecasted transactions. We 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, we will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by us through the utilization of market data, will be recognized within other income (loss) in our consolidated statements of operations. For derivatives previously qualifying as hedges, we recognized the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss) and reclassified the portion relating to commodity derivatives to natural gas and liquids revenue and the portion relating to interest rate derivatives to interest expense within our consolidated statements of operations as the underlying transactions were settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within other income (loss), net in our consolidated statements of operations as they occur.

Beginning July 1, 2008, we discontinued hedge accounting for our existing commodity derivatives which were qualified as hedges for accounting purposes. In addition, beginning May 29, 2009, we discontinued hedge accounting for our existing interest rate

 

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derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in our consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008 and interest rate derivative instruments at May 29, 2009, which were recognized in accumulated other comprehensive loss within partners’ capital on our consolidated balance sheet, will be reclassified to our consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

During the nine months ended September 30, 2009 and year ended December 31, 2008, we made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. Substantially all of these derivative contracts were put into place simultaneously with our acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the three and nine months ended September 30, 2009 and 2008, we recognized the following derivative activity related to the termination of these derivative instruments within our consolidated statements of operations (amounts in thousands):

 

		Early Termination of Derivative Contracts
		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Net cash derivative expense included within other income (loss), net		$	—			$	(70,258	)		$	(5,000	)		$	(186,068	)
Net cash derivative expense included within natural gas and liquids revenue		$	—			$	(1,258	)		$	—			$	(1,573	)
Net non-cash derivative income (expense) included within other income (loss), net		$	15,488			$	6,488			$	34,708			$	(39,857	)
Net non-cash derivative expense included within natural gas and liquids		$	(19,976	)		$	(19,514	)		$	(54,043	)		$	(19,514	)

In addition, at September 30, 2009, $6.6 million will be reclassified from accumulated other comprehensive loss within partner’s capital on our consolidated balance sheet and recognized as non-cash derivative expense during the period beginning on October 1, 2009 and ending on December 31, 2009, the remaining period for which the derivatives were originally scheduled to be settled, as a result of the early termination of certain derivatives that were classified as cash flow hedges in accordance with FASB ASC at the date of termination.

The following table summarizes our derivative activity, including the early termination of derivative contracts disclosed above, for the periods indicated (amounts in thousands):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Loss from cash settlement and non-cash recognition of qualifying hedge instruments(1)		$	(9,779	)		$	(27,419	)		$	(37,281	)		$	(78,214	)
Gain (loss) from change in market value of non-qualifying derivatives(2)		$	12,021			$	190,013			$	(30,460	)		$	(17,919	)
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2)		$	—			$	44,997			$	10,813			$	41,271
Gain (loss) from cash settlement and non-cash recognition of non-qualifying derivatives(2)		$	(10,165	)		$	(84,207	)		$	3,225			$	(280,696	)
Loss from cash settlement of qualifying interest rate derivatives(3)		$	(3,148	)		$	(673	)		$	(9,003	)		$	(867	)
Loss from change in market value of non-qualifying interest rate derivatives (2)		$	(823	)		$	—			$	(823	)		$	—

 

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(1)	Included within natural gas and liquids revenue on our consolidated statements of operations.

(2)	Included within other income (loss), net on our consolidated statements of operations.

(3)	Included within interest expense on our consolidated statements of operations.

The following table summarizes our gross fair values of derivative instruments for the period indicated (amounts in thousands):

 

		September 30, 2009
		Asset Derivatives					Liability Derivatives
		Balance Sheet Location		Fair Value			Balance Sheet Location		Fair Value
Derivatives not designated as hedging instruments:
Interest rate contracts		N/A		$	—		Current portion of derivative liability		$	(5,907	)
Commodity contracts		Current portion of derivative asset			4,514
Commodity contracts		Long-term derivative asset			1,980
Commodity contracts		Current portion of derivative liability			10,050		Current portion of derivative liability			(45,162	)
Commodity contracts		Long-term derivative liability			3,341		Long-term derivative liability			(12,597	)
				$	19,885				$	(63,666	)

The following table summarizes the gross effect of derivative instruments on our consolidated statements of operations for the period indicated (amounts in thousands):

 

		Derivatives not designated as hedging instruments Three months ended September 30, 2009
		Gain (Loss) Recognized in Accumulated OCI			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)						Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
					Amount				Location		Amount				Location
Interest rate contracts(1)		$	30		$	(3,057	)		Interest expense		$	(823	)		N/A
Commodity contracts(1)			—			(10,294	)		Natural gas and liquids revenue			(13,671	)		Other income (loss), net
Commodity contracts(2)			—			—			N/A			16,036			Other income (loss), net
		$	30		$	(13,351	)				$	1,542

 

(1)	Hedges previously designated as cash flow hedges

(2)	Dedesignated cash flow hedges and non-designated hedges

 

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		Derivatives not designated as hedging instruments Nine months ended September 30, 2009
		Gain (Loss) Recognized in Accumulated OCI				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)						Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
						Amount				Location		Amount				Location
Interest rate contracts(1)		$	(2,268	)		$	(8,912	)		Interest expense		$	(823	)		N/A
Commodity contracts(1)			—				(37,158	)		Natural gas and liquids revenue			(36,579	)		Other income (loss), net
Commodity contracts(2)			—				—			N/A			20,155			Other income (loss), net
		$	(2,268	)		$	(46,070	)				$	(17,247	)

 

(1)	Hedges previously designated as cash flow hedges

(2)	Dedesignated cash flow hedges and non-designated hedges

As of September 30, 2009, we had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

 

Term		Notional Amount			Type		Contract Period Ended December 31,		Fair Value Liability(1)
									(in thousands)
January 2008 - January 2010		$	200,000,000		Pay 2.88% — Receive LIBOR		2009		$	(1,335	)
							2010			(426	)
									$	(1,761	)
April 2008 - April 2010		$	250,000,000		Pay 3.14% — Receive LIBOR		2009		$	(1,832	)
							2010			(2,314	)
									$	(4,146	)

Natural Gas Sales – Fixed Price Swaps

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Asset (3)
2009		120,000		$	8.000		$	390

Natural Gas Basis Sales

 

Production Period Ended December 31,		Volumes		Average Fixed Price				Fair Value Liability (3)
		(mmbtu)(6)		(per mmbtu)(6)				(in thousands)
2009		1,230,000		$	(0.558	)		$	(386	)
2010		2,220,000		$	(0.607	)			(401	)
								$	(787	)

Natural Gas Purchases – Fixed Price Swaps

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability (3)
		(mmbtu)(6)		(per mmbtu)(6)			(in thousands)
2009		2,580,000		$	8.687		$	(10,162	)
2010		4,380,000		$	8.635			(11,718	)
							$	(21,880	)

 

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Natural Gas Basis Purchases

 

Production Period Ended December 31,		Volumes		Average Fixed Price				Fair Value Asset(3)
		(mmbtu)(6)		(per mmbtu)(6)				(in thousands)
2009		3,690,000		$	(0.659	)		$	1,508
2010		6,600,000		$	(0.590	)			1,193
								$	2,701

Natural Gas Liquid Sales – Fixed Price Swaps

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability(2)
		(gallons)		(per gallon)			(in thousands)
2009		5,544,000		$	0.754		$	(762	)

Ethane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Liability(1)				Option Type
		(gallons)		(per gallon)			(in thousands)
2009		630,000		$	0.340		$	(57	)		Puts purchased

Propane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Asset(1)			Option Type
		(gallons)		(per gallon)			(in thousands)
2009		15,246,000		$	0.820		$	579		Puts purchased

Isobutane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Liability(1)				Option Type
		(gallons)		(per gallon)			(in thousands)
2009		126,000		$	0.5890		$	(20	)		Puts purchased

Normal Butane Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Asset(1)			Option Type
		(gallons)		(per gallon)			(in thousands)
2009		3,654,000		$	0.943		$	98		Puts purchased
2010		3,654,000		$	1.038		$	544		Puts purchased
							$	642

 

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Natural Gasoline Put Options

 

Production Period Ended December 31,		Associated NGL Volume		Average Price(4)			Fair Value Asset(1)			Option Type
		(gallons)		(per gallon)			(in thousands)
2009		3,906,000		$	1.341		$	549		Puts purchased
2010		3,906,000		$	1.345		$	902		Puts purchased
							$	1,451

Crude Oil Sales Options (associated with NGL volume)

 

Production Period Ended December 31,		Crude Volume		Associated NGL Volume		Average Crude Price (4)			Fair Value Asset (Liability)(3)				Option Type
		(barrels)		(gallons)		(per barrel)			(in thousands)
2009		165,000		9,321,900		$	63.53		$	856			Puts purchased
2009		527,700		29,874,978		$	84.80			(647	)		Calls sold
2010		486,000		27,356,700		$	61.24			4,111			Puts purchased
2010		3,127,500		213,088,050		$	86.20			(20,462	)		Calls sold
2010		714,000		45,415,440		$	132.17			705			Calls purchased(5)
2011		606,000		33,145,560		$	100.70			(4,517	)		Calls sold
2011		252,000		13,547,520		$	133.16			920			Calls purchased(5)
2012		450,000		25,893,000		$	102.71			(4,038	)		Calls sold
2012		180,000		9,676,800		$	134.27			919			Calls purchased(5)
									$	(22,153	)

Crude Oil Sales

 

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability(3)
		(barrels)		(per barrel)			(in thousands)
2009		6,000		$	62.700		$	(48	)

Crude Oil Sales Options

 

Production Period Ended December 31,		Volumes		Average Crude Price(4)			Fair Value Asset (Liability)(3)				Option Type
		(barrels)		(per barrel)			(in thousands)
2009		117,000		$	64.151		$	604			Puts purchased
2009		76,500		$	84.956			(116	)		Calls sold
2010		411,000		$	64.732			4,450			Puts purchased
2010		234,000		$	88.088			(1,475	)		Calls sold
2011		72,000		$	93.109			(746	)		Calls sold
2012		48,000		$	90.314			(647	)		Calls sold
							$	2,070
		Total net liability					$	(43,781	)

 

(1)	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

(2)	Fair value based upon management estimates, including forecasted forward NGL prices.

(3)	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

(4)	Average price of options based upon average strike price adjusted by average premium paid or received.

 

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(5)	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

(6)	Mmbtu represents million British Thermal Units.

 

ITEM 4.

CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our General Partner’s Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our General Partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that at September 30, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

 

ITEM 1A.

RISK FACTORS

There have been no material changes in our risk factors from those disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008.

 

ITEM 6.

EXHIBITS

 

Exhibit No.		Description
3.1		Certificate of Limited Partnership(1)
3.2(a)		Second Amended and Restated Agreement of Limited Partnership(2)
3.2(b)		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership(3)
3.2(c)		Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership(4)
3.2(d)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership(6)
3.2(e)		Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership(7)

 

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3.2(f)		Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership(11)
3.2(g)		Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership(14)
3.3		Amended and Restated Certificate of Designation for 12% Cumulative Convertible Class B Preferred Units(14)
4.1		Common unit certificate(1)
4.2		8 1/8% Senior Notes Indenture dated December 20, 2005(12)
4.3		8 3/4% Senior Notes Indenture dated June 27, 2008(9)
10.1(a)		Revolving Credit and Term Loan Agreement dated July 27, 2007 by and among Atlas Pipeline Partners, L.P., Wachovia Bank, National Association and the several guarantors and lenders thereto(4)
10.1(b)		Amendment No. 1 and Agreement to the Revolving Credit and Term Loan Agreement, dated June 12, 2008(7)
10.1(c)		Increase Joinder dated June 27, 2008(10)
10.1(d)		Amendment No. 2 to Revolving Credit and Term Loan Agreement, dated May 29, 2009(16)
10.2		Class B Preferred Unit Purchase Agreement dated December 30, 2008, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P.(11)
10.3		Registration Rights Agreement dated December 30, 2008, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. (11)
10.4		Purchase Agreement dated as of January 27, 2009, between Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, Sunlight Capital Partners, LLC, Elliott Associates, L.P. and Elliott International, L.P. (5)
10.5		Form of Common Unit Purchase Agreement dated August 17, 2009, by and among Atlas Pipeline Partners, L.P. and the purchasers party thereto(20)
10.6		Form of Registration Rights Agreement dated August 20, 2009, by and among Atlas Pipeline Partners, L.P. and the purchasers party thereto (20)
10.7		Form of Warrant to purchase common units dated August 20, 2009(20)
10.8		Purchase Option Agreement between Atlas Pipeline Mid-Continent WestTex, LLC and Pioneer Natural Resources USA, Inc. dated July 27, 2007(4)
10.9		Long-Term Incentive Plan(13)
10.10		Formation and Exchange Agreement dated March 31, 2009 between Williams Field Services Group, LLC, Williams Laurel Mountain, LLC, Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P. and APL Laurel Mountain, LLC(15)
10.11		Employment agreement, dated as of January 15, 2009, between Atlas America, Inc. and Eugene N. Dubay(15)

 

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10.12		Securities Purchase Agreement dated April 7, 2009, by and between Atlas Pipeline Mid-Continent, LLC and Spectra Energy Partners OLP, LP(19)
10.13(a)		Revolving Credit Agreement among Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association, and other banks party thereto, dated as of July 26, 2006(19)
10.13(b)		First Amendment to the Revolving Credit Agreement dated June 1, 2009, by and among Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association and the lenders thereunder(17)
10.14		Atlas Pipeline Holdings II, LLC Limited Liability Company Agreement(17)
10.15		ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC, Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources, LLC(18)
10.16		Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream, LLC dated as of June 1, 2009(18)
10.17		Letter Agreement, dated as of August 31, 2009, between Atlas America, Inc. and Eric Kalamaras
10.18		Phantom Unit Grant Agreement between Atlas Pipeline Mid-Continent, LLC and Eric Kalamaras, dated September 14, 2009
12.1		Statement of Computation of Ratio of Earnings to Fixed Charges
31.1		Rule 13a-14(a)/15d-14(a) Certification
31.2		Rule 13a-14(a)/15d-14(a) Certification
32.1		Section 1350 Certification
32.2		Section 1350 Certification

 

(1)	Previously filed as an exhibit to registration statement on Form S-1 on January 20, 2000.

(2)	Previously filed as an exhibit to registration statement on Form S-3 on April 2, 2004.

(3)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2007.

(4)	Previously filed as an exhibit to current report on Form 8-K on July 30, 2007.

(5)	Previously filed as an exhibit to current report on Form 8-K on January 29, 2009.

(6)	Previously filed as an exhibit to current report on Form 8-K on January 8, 2008.

(7)	Previously filed as an exhibit to current report on Form 8-K on June 16, 2008.

(8)	[Intentionally omitted].

(9)	Previously filed as an exhibit to current report on Form 8-K on June 27, 2008.

(10)	Previously filed as an exhibit to current report on Form 8-K on July 3, 2008.

(11)	Previously filed as an exhibit to current report on Form 8-K on January 6, 2009.

(12)	Previously filed as an exhibit to current report on Form 8-K on December 21, 2005.

(13)	Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008.

(14)	Previously filed as an exhibit to current report on Form 8-K on April 3, 2009.

(15)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009.

(16)	Previously filed as an exhibit to current report on Form 8-K on June 1, 2009.

(17)	Previously filed as an exhibit to current report on Form 8-K on June 2, 2009.

(18)	Previously filed as an exhibit to current report on Form 8-K on June 5, 2009.

(19)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2009.

(20)	Previously filed as an exhibit to current report on Form 8-K on August 20, 2009.

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

		ATLAS PIPELINE PARTNERS, L.P.
		By:		Atlas Pipeline Partners GP, LLC,
				its General Partner
Date: November 6, 2009		By:		/S/    EUGENE N. DUBAY
				Eugene N. Dubay
				Chief Executive Officer, President and Managing Board Member of the General Partner
Date: November 6, 2009		By:		/S/    ERIC T. KALAMARAS
				Eric T. Kalamaras
				Chief Financial Officer of the General Partner
Date: November 6, 2009		By:		/S/    SEAN P. MCGRATH
				Sean P. McGrath
				Chief Accounting Officer of the General Partner

 

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