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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 June 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: 1-32953
ATLAS PIPELINE HOLDINGS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE | 43-2094238 | |
(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 ¨ | Accelerated filer x | Non-accelerated filer ¨ | Smaller reporting company ¨ | |||
(Do not check if a 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 August 5, 2009 was 27,659,154.
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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
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ITEM 1. | FINANCIAL STATEMENTS |
ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
(Unaudited)
June 30, 2009 | December 31, 2008 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 2,164 | $ | 7,285 | ||||
Accounts receivable – affiliates | — | 341 | ||||||
Accounts receivable | 77,118 | 100,000 | ||||||
Current portion of derivative asset | 1,815 | 44,961 | ||||||
Prepaid expenses and other | 13,401 | 10,998 | ||||||
Current assets of discontinued operations | — | 13,441 | ||||||
Total current assets | 94,498 | 177,026 | ||||||
Property, plant and equipment, net | 1,726,027 | 1,781,011 | ||||||
Intangible assets, net | 180,869 | 193,647 | ||||||
Investment in joint venture | 133,803 | — | ||||||
Long-term portion of derivative asset | 1,606 | — | ||||||
Other assets, net | 34,157 | 25,135 | ||||||
Long-term assets of discontinued operations | — | 242,165 | ||||||
$ | 2,170,960 | $ | 2,418,984 | |||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 31,000 | $ | — | ||||
Accounts payable – affiliates | 1,595 | — | ||||||
Accounts payable | 21,348 | 66,571 | ||||||
Accrued liabilities | 20,785 | 15,862 | ||||||
Current portion of derivative liability | 58,204 | 60,947 | ||||||
Accrued producer liabilities | 47,066 | 66,846 | ||||||
Current liabilities of discontinued operations | — | 10,572 | ||||||
Total current liabilities | 179,998 | 220,798 | ||||||
Long-term derivative liability | 12,748 | 48,333 | ||||||
Long-term debt, less current portion | 1,276,300 | 1,539,427 | ||||||
Other long-term liability | 490 | 574 | ||||||
Commitments and contingencies | ||||||||
Partners’ capital: | ||||||||
Common limited partners’ interests | 3,938 | (5,463 | ) | |||||
Accumulated other comprehensive loss | (10,686 | ) | (15,788 | ) | ||||
(6,748 | ) | (21,251 | ) | |||||
Non-controlling interests | (29,936 | ) | (32,337 | ) | ||||
Non-controlling interest in Atlas Pipeline Partners, L.P. | 738,108 | 663,440 | ||||||
Total partners’ capital | 701,424 | 609,852 | ||||||
$ | 2,170,960 | $ | 2,418,984 | |||||
See accompanying notes to consolidated financial statements
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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Revenue: | ||||||||||||||||
Natural gas and liquids | $ | 176,888 | $ | 430,334 | $ | 332,038 | $ | 789,949 | ||||||||
Transportation, compression and other fees – affiliates | 6,429 | 11,421 | 16,497 | 20,580 | ||||||||||||
Transportation, compression and other fees – third parties | 3,981 | 5,671 | 7,855 | 10,667 | ||||||||||||
Equity income in joint venture | 710 | — | 710 | — | ||||||||||||
Gain on asset sale | 109,941 | — | 109,941 | — | ||||||||||||
Other loss, net | (15,841 | ) | (314,256 | ) | (10,691 | ) | (401,007 | ) | ||||||||
Total revenue and other loss, net | 282,108 | 133,170 | 456,350 | 420,189 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Natural gas and liquids | 129,676 | 349,711 | 264,421 | 623,537 | ||||||||||||
Plant operating | 14,128 | 14,831 | 27,951 | 29,766 | ||||||||||||
Transportation and compression | 2,791 | 2,645 | 6,122 | 4,959 | ||||||||||||
General and administrative | 6,938 | 9,049 | 16,705 | 13,945 | ||||||||||||
Compensation reimbursement – affiliates | 375 | 1,390 | 750 | 2,519 | ||||||||||||
Depreciation and amortization | 22,999 | 20,412 | 45,667 | 40,459 | ||||||||||||
Interest | 26,852 | 20,204 | 48,517 | 41,396 | ||||||||||||
Total costs and expenses | 203,759 | 418,242 | 410,133 | 756,581 | ||||||||||||
Income (loss) from continuing operations | 78,349 | (285,072 | ) | 46,217 | (336,392 | ) | ||||||||||
Discontinued operations: | ||||||||||||||||
Gain on sale of discontinued operations | 51,078 | — | 51,078 | — | ||||||||||||
Income from discontinued operations | 2,541 | 8,245 | 11,417 | 14,491 | ||||||||||||
Income from discontinued operations | 53,619 | 8,245 | 62,495 | 14,491 | ||||||||||||
Net income (loss) | 131,968 | (276,827 | ) | 108,712 | (321,901 | ) | ||||||||||
Income attributable to non-controlling interests | (652 | ) | (3,112 | ) | (1,121 | ) | (5,202 | ) | ||||||||
(Income) loss attributable to non-controlling interest in Atlas Pipeline Partners, L.P. | (114,330 | ) | 241,738 | (93,688 | ) | 286,082 | ||||||||||
Net income (loss) attributable to common limited partners | $ | 16,986 | $ | (38,201 | ) | $ | 13,903 | $ | (41,021 | ) | ||||||
Net income (loss) attributable to common limited partners per unit: | ||||||||||||||||
Basic: | ||||||||||||||||
Continuing operations | $ | 0.34 | $ | (1.42 | ) | $ | 0.18 | $ | (1.54 | ) | ||||||
Discontinued operations | 0.27 | 0.04 | 0.32 | 0.05 | ||||||||||||
$ | 0.61 | $ | (1.38 | ) | $ | 0.50 | $ | (1.49 | ) | |||||||
Diluted: | ||||||||||||||||
Continuing operations | $ | 0.34 | $ | (1.42 | ) | $ | 0.18 | $ | (1.54 | ) | ||||||
Discontinued operations | 0.27 | 0.04 | 0.32 | 0.05 | ||||||||||||
$ | 0.61 | $ | (1.38 | ) | $ | 0.50 | $ | (1.49 | ) | |||||||
Weighted average common limited partner units outstanding: | ||||||||||||||||
Basic | 27,659 | 27,374 | 27,659 | 27,362 | ||||||||||||
Diluted | 27,659 | 27,374 | 27,659 | 27,362 | ||||||||||||
Amounts attributable to common limited partners: | ||||||||||||||||
Continuing operations | $ | 9,547 | $ | (39,310 | ) | $ | 5,034 | (42,415 | ) | |||||||
Discontinued operations | 7,439 | 1,109 | 8,869 | 1,394 | ||||||||||||
Net income (loss) attributable to common limited partners | $ | 16,986 | $ | (38,201 | ) | $ | 13,903 | $ | (41,021 | ) | ||||||
See accompanying notes to consolidated financial statements
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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
FOR THE SIX MONTHS ENDED JUNE 30, 2009
(in thousands, except unit data)
(Unaudited)
Common Limited Partners’ Capital | Accumulated Other Comprehensive Income (Loss) | Non- Controlling Interests | Non-Controlling Interest in Atlas Pipeline Partners L.P. | Total Partners’ Capital (Deficit) | ||||||||||||||||||
Units | $ | |||||||||||||||||||||
Balance at January 1, 2009 | 27,659,154 | $ | (5,463 | ) | $ | (15,788 | ) | $ | (32,337 | ) | $ | 663,440 | $ | 609,852 | ||||||||
Issuance of common limited partner units | — | (39 | ) | — | — | — | (39 | ) | ||||||||||||||
Distributions to non-controlling interests | — | — | — | 1,280 | (44,716 | ) | (43,436 | ) | ||||||||||||||
Unissued common units under incentive plans | — | (368 | ) | — | — | — | (368 | ) | ||||||||||||||
Distributions paid to common limited partners | — | (1,660 | ) | — | — | — | (1,660 | ) | ||||||||||||||
Distributions equivalent rights paid on unissued units under incentive plans | — | (15 | ) | — | — | — | (15 | ) | ||||||||||||||
Other comprehensive income | — | — | 5,102 | — | 25,696 | 30,798 | ||||||||||||||||
Net loss on purchase and sale of subsidiary equity | — | (2,420 | ) | — | — | — | (2,420 | ) | ||||||||||||||
Net income | — | 13,903 | — | 1,121 | 93,688 | 108,712 | ||||||||||||||||
Balance at June 30, 2009 | 27,659,154 | $ | 3,938 | $ | (10,686 | ) | $ | (29,936 | ) | $ | 738,108 | $ | 701,424 | |||||||||
See accompanying notes to consolidated financial statements
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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
Six Months Ended June 30, | ||||||||
2009 | 2008 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income (loss) | $ | 108,712 | $ | (321,901 | ) | |||
Less: Income from discontinued operations | 62,495 | 14,491 | ||||||
Net income (loss) from continuing operations | 46,217 | (336,392 | ) | |||||
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by operating activities: | ||||||||
Distributions paid to non-controlling interests in Atlas Pipeline Partners, L.P. | (22,337 | ) | (62,397 | ) | ||||
Depreciation and amortization | 45,667 | 40,459 | ||||||
Non-cash loss on derivative value, net | 34,010 | 201,834 | ||||||
Equity income in joint venture | (710 | ) | — | |||||
Gain on asset sale | (109,941 | ) | — | |||||
Distribution received from joint venture | 164 | — | ||||||
Non-cash compensation income | (109 | ) | (244 | ) | ||||
Amortization of deferred finance costs | 4,715 | 2,669 | ||||||
Net distributions to non-controlling interests | 1,280 | (5,052 | ) | |||||
Change in operating assets and liabilities, net of effects of acquisitions: | ||||||||
Accounts receivable, prepaid expenses and other | 20,405 | (42,342 | ) | |||||
Accounts payable and accrued liabilities | (18,655 | ) | 182,064 | |||||
Accounts payable and accounts receivable – affiliates | 1,935 | (259 | ) | |||||
Net cash provided by (used in) continuing operations | 2,641 | (19,660 | ) | |||||
Net cash provided by discontinued operations | 16,935 | 21,851 | ||||||
Net cash provided by operating activities | 19,576 | 2,191 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Acquisition purchase price adjustment | — | 31,429 | ||||||
Capital expenditures | (130,494 | ) | (142,054 | ) | ||||
Net proceeds from asset sale | 87,795 | — | ||||||
Other | (2,346 | ) | 342 | |||||
Net cash used in continuing investing activities | (45,045 | ) | (110,283 | ) | ||||
Net cash provided by (used in) discontinued investing activities | 290,594 | (15,143 | ) | |||||
Net cash provided by (used in) investing activities | 245,549 | (125,426 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Repayment of Atlas Pipeline Partners, L.P. debt | (247,295 | ) | (122,820 | ) | ||||
Net proceeds from subordinate loan with Atlas America, Inc. | 15,000 | — | ||||||
Net proceeds from issuance of Atlas Pipeline Partners, L.P. debt | — | 244,854 | ||||||
Borrowings under credit facility | — | 6,000 | ||||||
Borrowings under Atlas Pipeline Partners, L.P. credit facility | 325,000 | 163,000 | ||||||
Repayments under Atlas Pipeline Partners, L.P. credit facility | (305,000 | ) | (248,000 | ) | ||||
Repayments under credit facility | (30,000 | ) | — | |||||
Net proceeds from issuance of common limited partner units | — | 10,014 | ||||||
Net proceeds from issuance of Atlas Pipeline Partners, L.P. common limited partner units | — | 247,161 | ||||||
Redemption of Atlas Pipeline Partners, L.P. Class A preferred units | (15,000 | ) | — | |||||
Distributions paid to common limited partners | (1,660 | ) | (21,060 | ) | ||||
Other | (11,291 | ) | (5,532 | ) | ||||
Net cash provided by (used in) financing activities | (270,246 | ) | 273,617 | |||||
Net change in cash and cash equivalents | (5,121 | ) | 150,382 | |||||
Cash and cash equivalents, beginning of period | 7,285 | 12,490 | ||||||
Cash and cash equivalents, end of period | $ | 2,164 | $ | 162,872 | ||||
See accompanying notes to consolidated financial statements
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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2009
(Unaudited)
NOTE 1 – BASIS OF PRESENTATION
Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or the “Partnership”) is a publicly-traded Delaware limited partnership (NYSE: AHD). The Partnership’s wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or “General Partner”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). The Partnership’s general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”), which does not have an economic interest in the Partnership and is not entitled to receive any distributions from the Partnership, manages the operations and activities of the Partnership and owes a fiduciary duty to the Partnership’s common unitholders. At June 30, 2009, the Partnership had 27,659,154 common limited partnership units outstanding.
APL is a publicly-traded Delaware limited partnership and a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachian regions. APL’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 APL. The Partnership, through its general partner interests in APL and the Operating Partnership, owns a 2% general partner interest in the consolidated pipeline operations of APL, through which it manages and effectively controls both APL and the Operating Partnership. The remaining 98% ownership interest in the consolidated pipeline operations consists of limited partner interests in APL. The Partnership also owns 5,754,253 common limited partner units in APL (see Note 6) and 15,000 $1,000 par value Class B preferred limited partner units in APL (see Note 7). At June 30, 2009, APL had 47,804,175 common limited partnership units outstanding, including the 5,754,253 common units held by the Partnership and the 15,000 $1,000 par value Class B preferred units held by the Partnership (see Note 7).
The Partnership’s assets consist principally of 100% ownership interest in Atlas Pipeline GP, which owns:
• | a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL; |
• | all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter; Atlas Pipeline GP also agreed that the resulting allocation of incentive distribution rights back to APL would be after Atlas Pipeline GP receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter; |
• | 5,754,253 common units of APL, representing approximately 12.0% of the 47,804,175 outstanding common limited partnership units of APL; and |
• | 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units at June 30, 2009. |
The Partnership, as general partner, manages the operations and activities of APL and owes a fiduciary duty to APL’s common unitholders. The Partnership is liable, as general partner, for all of APL’s debts (to the extent not paid from APL’s assets), except for indebtedness or other obligations that are made specifically non-recourse to the Partnership. The Partnership does not receive
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any management fee or other compensation for its management of APL. The Partnership and its affiliates are reimbursed for expenses incurred on APL’s behalf. These expenses include the costs of employee, officer, and managing board member compensation and benefits properly allocable to APL and all other expenses necessary or appropriate to conduct the business of, and allocable to, APL. The APL partnership agreement provides that the Partnership, as general partner, will determine the expenses that are allocable to APL in any reasonable manner in its sole discretion.
Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), owns 100% of Atlas Pipeline Holdings GP, the general partner of the Partnership, and a 64.4% ownership interest in the Partnership at June 30, 2009. In addition to its ownership interest in the Partnership, Atlas America also owns 1,112,000 of APL’s common limited partnership units, representing a 2.3% ownership interest in it, and a 48.3% ownership interest in Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded company (NYSE: ATN). The majority of the natural gas APL and its affiliates, including Laurel Mountain, (see Note 3) transports in the Appalachian basin is derived from wells operated by Atlas Energy.
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 August 10, 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, APL 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 six month periods ended June 30, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In addition to matters discussed further within this note, a more thorough discussion of the 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 General Partner, APL, the Operating Partnership and the Operating Partnership’s wholly-owned and majority-owned subsidiaries. All material intercompany transactions have been eliminated.
The Partnership’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership 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.
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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. APL has an agreement with Pioneer whereby Pioneer has an option to buy up to an additional 22.0% interest in the Midkiff/Benedum system which began on June 15, 2009 and ends on November 1, 2009. If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22.0% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase option.
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 the Partnership’s and APL’s derivative instruments, the probability of forecasted transactions, APL’s allocation of purchase price to the fair value of assets it 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 six months ended June 30, 2009 represent actual results in all material respects (see “– Revenue Recognition” accounting policy for further description).
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, by the weighted average number of common limited partner units outstanding during the period.
On January 1, 2009, the Partnership adopted the Emerging Issues Task Force’s (“EITF”) Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of Financial Accounting Standards Board (“FASB”) Statement No. 128, “Earnings per Share” 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. 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, FSP EITF 03-6-1 provides that 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. FSP EITF 03-6-1 requires entities to retroactively adjust all prior period earnings per unit computations per its guidance.
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The following is a reconciliation of net income (loss) from continuing operations and net income from discontinued operations allocated to the 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 June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008(1) | 2009 | 2008(1) | |||||||||||||
Continuing operations: | ||||||||||||||||
Net income (loss) | $ | 78,349 | $ | (285,072 | ) | $ | 46,217 | $ | (336,392 | ) | ||||||
Income attributable to non-controlling interests | (652 | ) | (3,112 | ) | (1,121 | ) | (5,202 | ) | ||||||||
(Income) loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P. | (68,150 | ) | 248,874 | (40,062 | ) | 299,179 | ||||||||||
Net income (loss) attributable to common limited partners | 9,547 | (39,310 | ) | 5,034 | (42,415 | ) | ||||||||||
Less: Net income (loss) attributable to participating securities – phantom units(2) | 62 | (321 | ) | 36 | (345 | ) | ||||||||||
Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit | $ | 9,485 | $ | (38,989 | ) | $ | 4,998 | $ | (42,070 | ) | ||||||
Discontinued operations: | ||||||||||||||||
Net income | $ | 53,619 | $ | 8,245 | $ | 62,495 | $ | 14,491 | ||||||||
Income attributable to non-controlling interests – Atlas Pipeline Partners, L.P. | (46,180 | ) | (7,136 | ) | (53,626 | ) | (13,097 | ) | ||||||||
Net income utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit | $ | 7,439 | $ | 1,109 | $ | 8,869 | $ | 1,394 | ||||||||
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4). |
(2) | In accordance with FSP EITF 03-6-1, 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 June 30, | Six Months Ended June 30, | |||||||
2009 | 2008 | 2009 | 2008 | |||||
Weighted average number of common limited partner units – basic | 27,659 | 27,374 | 27,659 | 27,362 | ||||
Add: effect of dilutive option incentive awards(1) | — | — | — | — | ||||
Weighted average number of common limited partner units – diluted | 27,659 | 27,374 | 27,659 | 27,362 | ||||
(1) | For the three months ended June 30, 2009 and 2008, approximately 1.0 million and 1.2 million unit options, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such unit options would have been anti-dilutive. For the six months ended June 30, 2009 and 2008, approximately 1.0 million and 1.2 million unit options, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such unit options would have been anti-dilutive. |
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Non-Controlling Interest in Atlas Pipeline Partners, L.P.
The non-controlling interest in APL on the Partnership’s consolidated financial statements reflects the outside ownership interests in APL, which was 86.2% and 84.1% at June 30, 2009 and December 31, 2008, respectively. The non-controlling interests in APL in the Partnership’s consolidated statements of operations is calculated quarterly by multiplying (i) the weighted average APL common limited partner units outstanding held by non-affiliated third parties by (ii) the consolidated net income (loss) per APL common limited partner unit for the respective quarter. The net income (loss) per APL common limited partner unit is calculated by dividing the net income (loss) allocated to common limited partners, after the allocation of net income (loss) to the Partnership as general partner in accordance with the terms of the APL partnership agreement, by the total weighted average APL common limited partner units outstanding. The Partnership’s general partner interest in the net income (loss) of APL is based upon its 2% general partner ownership interest and incentive distributions, with a priority allocation of APL’s net income (loss) in an amount equal to the incentive distributions (see Note 8), in accordance with the APL partnership agreement, and the remaining APL net income (loss) allocated with respect to the general partner’s and APL’s limited partners’ ownership interests. The non-controlling interest in APL on the Partnership’s consolidated balance sheets principally reflects the sum of the allocation of APL’s consolidated net income (loss) to the non-controlling interest in APL and the contributed capital of non-controlling interests through the sale of limited partner units in APL, partially offset by APL quarterly cash distributions to the non-controlling interest owners.
During the six months ended June 30, 2009, APL issued 348,620 common units to certain key employees covered under incentive compensation agreements (see Note 15). Additionally, APL issued 1,465,653 of its common units upon conversion of 5,000 preferred units previously held by Sunlight Capital Partners, LLC (see Note 7). As a result of these transactions, the Partnership’s ownership percentage in APL, including its 2% interest as General Partner, was reduced. Pursuant to Securities and Exchange Commission Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary” (“SAB No. 51”), during the six months ended June 30, 2009, the Partnership recorded a $2.4 million increase to non-controlling interest in APL with a corresponding decrease to its limited partners’ capital, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the respective common unit transactions, on its consolidated balance sheet.
Impairment of Long-Lived Assets
The Partnership, including APL, 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.
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Capitalized Interest
APL 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 by APL was 5.8% and 5.9% for the three months ended June 30, 2009 and 2008, respectively, and 5.3% and 6.3% for the six months ended June 30, 2009 and 2008, respectively. The amount of interest capitalized was $0.5 million and $1.9 million for the three months ended June 30, 2009 and 2008, respectively, and $1.9 million and $3.5 million for the six months ended June 30, 2009 and 2008, respectively.
Intangible Assets
APL 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 June 30, 2009 and December 31, 2008 (in thousands):
June 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 | $ | (6,602 | ) | $ | (5,806 | ) | ||||
Customer relationships | (47,911 | ) | (35,929 | ) | ||||||
$ | (54,513 | ) | $ | (41,735 | ) | |||||
Net Carrying Amount: | ||||||||||
Customer contracts | $ | 6,208 | $ | 7,004 | ||||||
Customer relationships | 174,661 | 186,643 | ||||||||
$ | 180,869 | $ | 193,647 | |||||||
Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized 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, APL will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’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 APL’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 APL 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 of the three month periods ended June 30, 2009 and 2008, and $12.8 million for both of the six month periods ended June 30, 2009 and 2008. Amortization expense related to APL’s intangible assets is estimated to be as follows for each of the next five calendar years: 2009 to 2012 - $25.6 million; 2013 - $24.5 million.
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Goodwill
The changes in the carrying amount of goodwill for the six months ended June 30, 2009 and 2008 were as follows (in thousands):
Six Months Ended June 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 | |||
As a result of its impairment evaluation at December 31, 2008, APL recognized a $676.9 million non-cash impairment charge within the Partnership’s consolidated statements of operations during the fourth quarter of 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of its reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change.
During April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax received in April 2008, APL reduced goodwill recognized in connection with the acquisition at June 30, 2008.
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 for the Partnership include only changes in the fair value of unsettled APL derivative contracts which are accounted for as cash flow hedges (see Note 11). The following table sets forth the calculation of the Partnership’s comprehensive income (loss) (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Net income (loss) | $ | 131,968 | $ | (276,827 | ) | $ | 108,712 | $ | (321,901 | ) | ||||||
Income attributable to non-controlling interests | (652 | ) | (3,112 | ) | (1,121 | ) | (5,202 | ) | ||||||||
(Income) loss attributable to non-controlling interests - Atlas Pipeline Partners, L.P. | (114,330 | ) | 241,738 | (93,688 | ) | 286,082 | ||||||||||
Net income (loss) attributable to common limited partners | 16,986 | (38,201 | ) | 13,903 | (41,021 | ) | ||||||||||
Other comprehensive income (loss): | ||||||||||||||||
Change in fair value of derivative instruments accounted for as cash flow hedges | (869 | ) | (127,834 | ) | (2,246 | ) | (109,249 | ) | ||||||||
Changes in non-controlling interest related to items in other comprehensive income (loss) | (9,115 | ) | 92,280 | (25,696 | ) | 62,899 | ||||||||||
Add: adjustment for realized losses reclassified to net income (loss) | 14,019 | 18,677 | 33,044 | 36,320 | ||||||||||||
Total other comprehensive income (loss) | 4,035 | (16,877 | ) | 5,102 | (10,030 | ) | ||||||||||
Comprehensive income (loss) | $ | 21,021 | $ | (55,078 | ) | $ | 19,005 | $ | (51,051 | ) | ||||||
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Revenue Recognition
APL’s Mid-Continent segment revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:
Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.
POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.
Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.
Revenue in APL’s Appalachia segment is principally recognized at the time the natural gas is transported through its gathering systems.
APL 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 APL’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). APL had unbilled revenues at June 30, 2009 and December 31, 2008 of $45.9 million and $50.1 million, respectively, which are included in accounts receivable and accounts receivable-affiliates within the Partnership’s consolidated balance sheets.
Recently Adopted Accounting Standards
In May 2009, the FASB issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 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. SFAS No. 165 requires 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. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of SFAS No. 165 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 SFAS 165 does not change the Partnership’s current practices with respect to evaluating, recording and disclosing subsequent events.
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In April 2009, the FASB issued Staff Position 157-4, “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” (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 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 FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on the Partnership’s financial position and results of operations.
In April 2009, the FASB issued Staff Position 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2 and FAS 124-2”). FSP FAS 115-2 and FAS 124-2 change existing guidance for determining whether an impairment is other than temporary for debt securities. FSP FAS 115-2 and FAS 124-2 replaces the existing requirement that an entity’s management assess 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. FSP FAS 115-2 and FAS 124-2 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. FSP FAS 115-2 and FAS 124-2 are 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 FSP FAS 115-2 and FAS 124-2 on April 1, 2009 and its adoption did not have a material impact on the Partnership’s financial position and results of operations.
In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 APB 28-1 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. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on the Partnership’s financial position and results of operations.
In April 2009, the FASB issued Staff Position 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141(R)-1”). FSP 141(R)-1 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 FASB Statement No. 5, “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss”. FSP 141(R)-1 also eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. FSP FAS 141(R)-1 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 of FSP 141(R)-1 on January 1, 2009 and its adoption did not have a material impact on the Partnership’s financial position and results of operations.
In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable
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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. FSP EITF 03-6-1 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 of FSP EITF 03-6-1 on January 1, 2009 and its adoption did not have a material impact on the Partnership’s financial position and results of operations (see “Net Income (Loss) Per Common Unit”). Prior-period net loss per common limited partner unit data presented has been adjusted retrospectively to conform to the provisions of FSP EITF 03-6-1.
In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 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 FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. Generally Accepted Accounting Principles. The Partnership adopted the requirements of FSP FAS 142-3 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 ratified the EITF consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF 07-4 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. EITF 07-4 also 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 EITF No. 07-4 on January 1, 2009 did not have a material impact on its financial position and results of operations.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, 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 SFAS No. 161 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 SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish 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. SFAS No. 160 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, SFAS No. 160 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. SFAS No. 160 also requires that a 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 SFAS No. 160 on 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 the provisions of SFAS No. 160.
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In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”), however 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. SFAS No. 141(R) 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, SFAS No. 141 (R) 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 the requirements of SFAS No. 141(R) 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 June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, 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 Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership will apply the requirements of SFAS No. 168 to its financial statements for the interim period ending September 30, 2009 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 Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” and 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. SFAS No. 167 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. SFAS No. 167 is 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 the requirements of SFAS No. 167 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 – APL INVESTMENT IN JOINT VENTURE
On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain Midstream LLC (“Laurel Mountain”), a joint venture which will own and operate APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. To the joint venture, Williams contributed cash of $100.0 million, of which APL received approximately $87.8 million, net of working capital adjustments, and a note receivable of $25.5 million. APL contributed its Appalachia Basin natural gas gathering system and retained a 49% ownership interest in Laurel Mountain. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership
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interest in Laurel Mountain as an investment in joint venture on the Partnership’s consolidated balance sheet at fair value and recognized a gain on sale of $109.9 million, including $79.7 million associated with the remeasurement of APL’s investment in Laurel Mountain to fair value. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 13). In addition, Atlas Energy sold to Laurel Mountain two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $10.0 million. Upon the completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with Atlas Energy which superseded the existing natural gas gathering agreements and omnibus agreement between APL and Atlas Energy. Under the new gas gathering agreement, Atlas Energy 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 partnerships’ gas). APL has accounted for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain as equity income on the Partnership’s consolidated statements of operations.
The following table provides summarized statement of operations and balance sheet data on a 100 % basis for Laurel Mountain for the three and six months ended June 30, 2009 and as of June 30, 2009 (in thousands):
Three Months Ended June 30, 2009(1) | Six Months Ended June 30, 2009(1) | |||||
Statement of Operations data: | ||||||
Total revenue | $ | 3,068 | $ | 3,068 | ||
Net income | 1,278 | 1,278 | ||||
June 30, 2009 | ||||||
Balance Sheet data: | ||||||
Current assets | $ | 7,565 | ||||
Long-term assets | 245,395 | |||||
Current liabilities | 11,104 | |||||
Long-term liabilities | 15,500 | |||||
Net equity | 226,356 |
(1) | Represents the period from May 31, 2009, the date of initial formation, through June 30, 2009. |
NOTE 4 – DISCONTINUED OPERATIONS
On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra (see Note 18). APL 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 APL’s NOARK assets within income from discontinued operations on its consolidated statements of operations for the three and six months ended June 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 June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Total revenue and other loss, net | $ | 5,269 | $ | 15,988 | $ | 21,274 | $ | 32,359 | ||||||||
Total costs and expenses | (2,728 | ) | (7,743 | ) | (9,857 | ) | (17,868 | ) | ||||||||
Income from discontinued operations | $ | 2,541 | $ | 8,245 | $ | 11,417 | $ | 14,491 | ||||||||
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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 – ATLAS PIPELINE HOLDINGS EQUITY OFFERINGS
On June 1, 2009, a newly created, wholly-owned subsidiary of the Partnership, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash pursuant to a certificate of designation. The Partnership utilized the net proceeds from the issuance to reduce borrowings under its senior secured credit facility (see Note 13). Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for the Partnership’s common units. Distributions on the AHD Sub Preferred Units shall initially be paid in cash or by increasing the amount of the AHD Sub Preferred Unit equity by the amount of the distribution. However, under the terms of the certificate of designation, prior to the repayment of all outstanding borrowings under the Partnership’s credit facility (see Note 13), AHD Sub may only pay a cash distribution on the AHD Sub Preferred Units if the Partnership has received distributions on APL’s 12.0% Class B preferred units (see Note 7). After the Partnership has repaid all outstanding borrowings under its credit facility, all subsequent distributions declared by AHD Sub on the AHD Sub Preferred Units shall be paid in cash. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units, subject to certain limitations under the terms of the certificate of designation. As APL owns all of the outstanding AHD Sub Preferred Units in an amount equal to the Class B Preferred Units of APL that the Partnership owns (see Note 7), the amounts eliminate in consolidation of the Partnership’s consolidated balance sheet as of June 30, 2009.
In June 2008, the Partnership sold 308,109 common units through a private placement to Atlas America at a price of $32.50 per unit, for net proceeds of approximately $10.0 million. The Partnership utilized the net proceeds from the sale to purchase 278,000 common units of APL (see Note 6), which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 11). Following the Partnership’s private placement, Atlas America had a 64.4% ownership interest in the Partnership.
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NOTE 6 – APL COMMON UNIT EQUITY OFFERING
In June 2008, APL 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, APL sold 1,112,000 common units to Atlas America and 278,000 common units to the Partnership in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. APL also received a capital contribution from the Partnership of $5.4 million for it to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements (see Note 11).
NOTE 7 – APL PREFERRED UNIT EQUITY OFFERINGS
APL Class A Preferred Units
In January 2009, APL 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 “APL 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 APL Class A Preferred Units of April 1, 2009, (c) established Sunlight Capital’s new conversion option price of $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of its common units, and (d) established a new price for APL’s call redemption right of $27.25.
The amendment to the preferred units certificate of designation also required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 (see Note 13) to redeem 10,000 APL Class A Preferred Units. APL’s 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, the Partnership recorded the redemption by recognizing a $10.0 million reduction of non-controlling interest in APL, $15.0 million of additional long-term debt for the face value of the APL 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 APL’s 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) APL redeem 10,000 of the APL 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 APL Class A Preferred Units between April 1, 2009 and June 1, 2009, APL has the option of redeeming the APL Class A Preferred Units for cash at the stipulated liquidation value or converting the APL 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 APL Class A Preferred Units would have been required to be redeemed in cash, while APL had the option of redeeming the remaining 5,000 APL Class A Preferred Units in cash or converting the preferred units into its common limited partner units.
On April 1, 2009, APL redeemed 10,000 of the APL 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, APL paid Sunlight a preferred dividend of $0.3 million, representing the quarterly dividend on the 10,000 preferred units held by Sunlight prior to APL’s redemption. On April 13, 2009, APL converted 5,000 of the APL Class A Preferred Units into 1,465,653 APL common units in accordance with the terms of the amended preferred units certificate of designation. On May 5, 2009, APL redeemed the remaining 5,000 APL 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. Additionally on May 5, 2009, APL paid Sunlight a preferred dividend of $0.2 million, representing the quarterly dividend on the 5,000 preferred units held by Sunlight prior to APL’s redemption.
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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, APL, 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, APL amortized the remaining $0.5 million of this imputed dividend cost, which is presented within non-controlling interests in APL on the Partnership’s consolidated statements of operations for the six months ended June 30, 2008.
APL recognized $0.7 million of preferred dividend cost for the three months ended June 30, 2008 and $0.4 million and $0.8 million of preferred dividend cost for the six months ended June 30, 2009 and 2008, respectively, for dividends paid to the APL Class A preferred units, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners on the Partnership’s consolidated statements of operations.
APL Class B Preferred Units
In December 2008, APL sold 10,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “APL Class B Preferred Units”) to the Partnership for cash consideration of $1,000 per APL Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “APL Class B Preferred Units Certificate of Designation”). On March 30, 2009, the Partnership, pursuant to its right within the APL Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 APL Class B Preferred Units at Face Value. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes. The APL Class B Preferred Units receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The record date of determination for holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date of determination for APL’s common unit holders entitled to receive quarterly distributions. Additionally, on March 30, 2009, APL and the Partnership agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units are not convertible into APL common units. The amended APL Class B Preferred Units Certificate of Designation also gives APL the right at any time to redeem some or all of the outstanding APL Class B Preferred Units for cash at an amount equal to the APL 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 APL Class B Preferred Units or b) the number of remaining outstanding APL Class B Preferred Units.
The cumulative sale of the APL Class B Preferred Units to the Partnership was exempt from the registration requirements of the Securities Act of 1933. The Partnership received $0.5 million in preferred dividends for the six months ended June 30, 2009.
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NOTE 8 – CASH DISTRIBUTIONS
Atlas Pipeline Holdings Cash Distributions
The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2008 through June 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 | |||||
(in thousands) | ||||||||
February 19, 2008 | December 31, 2007 | $ | 0.34 | $ | 9,299 | |||
May 20, 2008 | March 31, 2008 | $ | 0.43 | $ | 11,761 | |||
August 19, 2008 | June 30, 2008 | $ | 0.51 | $ | 14,106 | |||
November 19, 2008 | September 30, 2008 | $ | 0.51 | $ | 14,106 | |||
February 19, 2009 | December 31, 2008 | $ | 0.06 | $ | 1,660 |
There was no cash distribution declared by the Partnership for the quarters ended March 31, 2009 or June 30, 2009. On June 1, 2009, the Partnership entered into an amendment to its credit facility agreement which, among other changes, prohibited it from paying any cash distributions on its equity while the credit facility is in effect (see Note 13).
APL Cash Distributions
APL 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 Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and General Partner distributions declared by APL for the period from January 1, 2008 through June 30, 2009 were as follows:
Date Cash Distribution Paid | For Quarter Ended | APL Cash Distribution per Common Limited Partner Unit | Total APL Cash Distribution To Common Limited Partners | Total APL 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 |
In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems in July 2007, the Partnership, which holds all of the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. The Partnership also agreed that the resulting allocation of incentive distribution rights back to APL would be after the Partnership receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.
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APL did not declare a cash distribution for the quarter ended June 30, 2009. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 13) which, among other changes, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.
NOTE 9 – PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment (in thousands):
June 30, 2009 | December 31, 2008(1) | Estimated Useful Lives in Years | ||||||||
Pipelines, processing and compression facilities | $ | 1,657,201 | $ | 1,707,046 | 15 – 40 | |||||
Rights of way | 166,595 | 168,057 | 20 – 40 | |||||||
Buildings | 8,923 | 8,920 | 40 | |||||||
Furniture and equipment | 9,417 | 9,279 | 3 – 7 | |||||||
Other | 12,736 | 13,002 | 3 – 10 | |||||||
1,854,872 | 1,906,304 | |||||||||
Less – accumulated depreciation | (128,845 | ) | (125,293 | ) | ||||||
$ | 1,726,027 | $ | 1,781,011 | |||||||
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4). |
NOTE 10 – OTHER ASSETS
The following is a summary of other assets (in thousands):
June 30, 2009 | December 31, 2008(1) | |||||
Deferred finance costs, net of accumulated amortization of $22,290 and $17,575 at June 30, 2009 and December 31, 2008, respectively | $ | 30,451 | $ | 23,818 | ||
Long-term pipeline lease prepayment | 2,043 | — | ||||
Security deposits | 1,663 | 1,317 | ||||
$ | 34,157 | $ | 25,135 | |||
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’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 May 2009, APL recorded $2.3 million of accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with the proceeds from the sale of its NOARK system (see Note 4). In June 2008, APL recorded $1.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with a portion of the net proceeds from its issuance of senior notes (see Note 13).
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NOTE 11 — DERIVATIVE INSTRUMENTS
The Partnership and APL use a number of different derivative instruments, principally swaps and options, in connection with their commodity price and interest rate risk management activities. APL 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. The Partnership and APL also enter into financial swap instruments to hedge certain portions of their 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, APL 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 and APL apply the provisions of SFAS No. 133 to their derivative instruments. APL formally documents all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching derivative contracts to the forecasted transactions. Under SFAS No. 133, the Partnership and APL can assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Partnership and APL through the utilization of market data, will be recognized within other income (loss), net in the Partnership’s consolidated statements of operations. For APL’s 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 APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within other loss, net in its consolidated statements of operations as they occur.
Beginning July 1, 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives are recognized immediately within other loss, net in the Partnership’s 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.
During the six months ended June 30, 2009 and year ended December 31 2008, APL 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 APL’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 six months ended June 30, 2009 and 2008, the Partnership recognized the following derivative activity related to APL’s termination of these derivative instruments within its consolidated statements of operations (amounts in thousands):
Early Termination of Derivative Contracts | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Net cash derivative expense included within other loss, net | $ | — | $ | (115,810 | ) | $ | (5,000 | ) | $ | (115,810 | ) | |||||
Net cash derivative expense included within natural gas and liquids revenue | — | (315 | ) | — | (315 | ) | ||||||||||
Net non-cash derivative income (expense) included within other loss, net | 7,117 | (46,345 | ) | 19,220 | (46,345 | ) | ||||||||||
Net non-cash derivative expense included within natural gas and liquids | (12,123 | ) | — | (34,067 | ) | — |
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At June 30, 2009, the Partnership had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, the Partnership will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 13), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is effective at June 30, 2009 and expires on May 28, 2010. In June 2009, the Partnership repaid a portion of its borrowings under the credit facility, with a resulting balance of $16.0 million outstanding under the credit facility at June 30, 2009. In addition, in accordance with the June 2009 amendment to its credit facility (see Note 13), the Partnership is prohibited from borrowing additional amounts under its credit facility once the amounts have been repaid. In accordance with SFAS No. 133, the portion of any gain or loss in other comprehensive income related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income and recognized within the statements of operations. As a result of this reduction in borrowings under the credit facility below the notional amount of the interest rate derivative contract, the Partnership recognized an expense of $0.2 million within other loss, net in its consolidated statement of operations for the three and six months ended June 30, 2009.
At June 30, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL 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 APL interest rate swap agreements were in effect as of June 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, APL discontinued hedge accounting for its interest rate derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives will be recognized immediately within other loss, net in the Partnership’s consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized 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.
The Partnership’s and APL’s derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. At June 30, 2009 and December 31, 2008, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $67.5 million and $64.3 million, respectively. Of the $10.7 million of net loss in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet at June 30, 2009, if the fair values of the instruments remain at current market values, the Partnership will reclassify $6.2 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period, consisting of $4.7 million of losses to natural gas and liquids revenue and $1.5 million of losses to interest expense. Aggregate losses of $4.5 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. Actual amounts that will be reclassified will vary as a result of future price or interest rate changes.
The fair value of the Partnership’s derivative instruments was included in its consolidated balance sheets as follows (in thousands):
June 30, 2009 | December 31, 2008 | |||||||
Current portion of derivative asset | $ | 1,815 | $ | 44,961 | ||||
Long-term derivative asset | 1,606 | — | ||||||
Current portion of derivative liability | (58,204 | ) | (60,947 | ) | ||||
Long-term derivative liability | (12,748 | ) | (48,333 | ) | ||||
$ | (67,531 | ) | $ | (64,319 | ) | |||
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The following table summarizes the Partnership’s and APL’s cumulative derivative activity for the periods indicated (amounts in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Loss from cash and non-cash settlement of qualifying hedge instruments(1) | $ | (7,327 | ) | $ | (33,152 | ) | $ | (27,502 | ) | $ | (50,795 | ) | ||||
Gain (loss) from change in market value of non-qualifying derivatives(2) | 2,509 | (136,736 | ) | (42,481 | ) | (207,932 | ) | |||||||||
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2) | — | 1,934 | 10,813 | (3,726 | ) | |||||||||||
Loss from cash and non-cash settlement of non-qualifying derivatives(2) | (21,105 | ) | (184,564 | ) | 13,390 | (196,489 | ) | |||||||||
Loss from cash settlement of interest rate derivatives(3) | (3,125 | ) | (207 | ) | (6,179 | ) | (207 | ) |
(1) | Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations. |
(2) | Included within other 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 and APL’s gross fair values of cumulative derivative instruments for the period indicated (amounts in thousands):
June 30, 2009 | |||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||
Derivatives designated as hedging instruments under SFAS No. 133: | |||||||||||
N/A | |||||||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | |||||||||||
Interest rate contracts | Current portion of derivative liability | $ | (8,715 | ) | |||||||
Commodity contracts | Current portion of derivative asset | $ | 1,815 | ||||||||
Commodity contracts | Long-term derivative asset | 1,606 | |||||||||
Commodity contracts | Current portion of derivative liability | 6,848 | Current portion of derivative liability | (56,337 | ) | ||||||
Commodity contracts | Long-term derivative liability | 3,151 | Long-term derivative liability | (15,899 | ) | ||||||
$ | 13,420 | $ | (80,951 | ) | |||||||
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The following table summarizes the gross effect of the Partnership’s and APL’s derivative instruments on the Partnership’s consolidated statement of operations for the period indicated (amounts in thousands):
Three months ended June 30, 2009 | ||||||||||||
Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | |||||||||
Derivatives in SFAS No. 133 cash flow hedging relationships: | ||||||||||||
N/A | ||||||||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | ||||||||||||
Interest rate contracts | $ | (3,125 | ) | Interest expense | $ | — | N/A | |||||
Commodity contracts(1) | (10,894 | ) | Natural gas and liquids revenue | (13,381 | ) | Other loss, net | ||||||
Commodity contracts(2) | — | N/A | (4,155 | ) | Other loss, net | |||||||
$ | (14,019 | ) | $ | (17,536 | ) | |||||||
(1) | Hedges previously designated as cash flow hedges |
(2) | Dedesignated cash flow hedges and non-designated hedges |
Six months ended June 30, 2009 | ||||||||||||
Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | |||||||||
Derivatives in SFAS No. 133 cash flow hedging relationships: | ||||||||||||
N/A | ||||||||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | ||||||||||||
Interest rate contracts | $ | (6,179 | ) | Interest expense | $ | — | N/A | |||||
Commodity contracts(1) | (26,864 | ) | Natural gas and liquids revenue | (22,908 | ) | Other loss, net | ||||||
Commodity contracts(2) | — | N/A | 35,665 | Other loss, net | ||||||||
$ | (33,043 | ) | $ | 12,757 | ||||||||
(1) | Hedges previously designated as cash flow hedges |
(2) | Dedesignated cash flow hedges and non-designated hedges |
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As of June 30, 2009, the Partnership had the following interest rate 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) | |||||||||||
May 2008-May 2010 | $ | 25,000,000 | Pay 3.01% —Receive LIBOR | 2009 | $ | (323 | ) | ||||
2010 | (221 | ) | |||||||||
$ | (544 | ) |
(1) | Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace. |
As of June 30, 2009, APL 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 | $ | (2,480 | ) | ||||
2010 | (351 | ) | |||||||||
$ | (2,831 | ) | |||||||||
April 2008-April 2010 | $ | 250,000,000 | Pay 3.14% —Receive LIBOR | 2009 | $ | (3,430 | ) | ||||
2010 | (1,910 | ) | |||||||||
$ | (5,340 | ) | |||||||||
Natural Gas Liquids Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(2) | ||||||
(gallons) | (per gallon) | (in thousands) | |||||||
2009 | 11,088,000 | $ | 0.745 | $ | (573 | ) | |||
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 | 234,000 | 13,185,000 | $ | 60.97 | $ | 1,234 | Puts purchased | ||||||
2009 | 1,055,400 | 59,081,820 | $ | 84.75 | (2,622 | ) | Calls sold | ||||||
2010 | 486,000 | 27,356,700 | $ | 61.24 | 3,838 | Puts purchased | |||||||
2010 | 3,127,500 | 213,088,050 | $ | 86.20 | (22,103 | ) | Calls sold | ||||||
2010 | 714,000 | 45,415,440 | $ | 132.17 | 708 | Calls purchased(5) | |||||||
2011 | 606,000 | 33,145,560 | $ | 100.70 | (4,065 | ) | Calls sold | ||||||
2011 | 252,000 | 13,547,520 | $ | 133.16 | 764 | Calls purchased(5) | |||||||
2012 | 450,000 | 25,893,000 | $ | 102.71 | (3,746 | ) | Calls sold | ||||||
2012 | 180,000 | 9,676,800 | $ | 134.27 | 801 | Calls purchased(5) | |||||||
$ | (25,191 | ) | |||||||||||
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Natural Gas Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset (3) | |||||
(mmbtu)(6) | (per mmbtu) (6) | (in thousands) | ||||||
2009 | 240,000 | $ | 8.000 | $ | 866 | |||
Natural Gas Basis Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset (3) | ||||||
(mmbtu)(6) | (per mmbtu)(6) | (in thousands) | |||||||
2009 | 2,460,000 | $ | (0.558 | ) | $ | 27 | |||
2010 | 2,220,000 | $ | (0.607 | ) | 124 | ||||
$ | 151 | ||||||||
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 | 5,160,000 | $ | 8.687 | $ | (22,156 | ) | ||||
2010 | 4,380,000 | $ | 8.635 | (12,414 | ) | |||||
$ | (34,570 | ) | ||||||||
Natural Gas Basis Purchases
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | |||||||
(mmbtu)(6) | (per mmbtu)(6) | (in thousands) | ||||||||
2009 | 7,380,000 | $ | (0.659 | ) | $ | (83 | ) | |||
2010 | 6,600,000 | $ | (0.590 | ) | (111 | ) | ||||
$ | (194 | ) | ||||||||
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 | $ | (40 | ) | 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 | 15,498,000 | $ | 0.767 | $ | 752 | Puts purchased | ||||
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Isobutane 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 | 1,134,000 | $ | 0.969 | $ | 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 | 9,324,000 | $ | 0.964 | $ | 585 | Puts purchased | ||||
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 | 5,796,000 | $ | 1.267 | $ | 358 | Puts purchased | ||||
Crude Oil Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | ||||||
(barrels) | (per barrel) | (in thousands) | |||||||
2009 | 15,000 | $ | 62.700 | $ | (131 | ) | |||
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 | 231,000 | $ | 63.017 | $ | 1,100 | Puts purchased | |||||
2009 | 153,000 | $ | 84.881 | (434 | ) | Calls sold | |||||
2010 | 174,000 | $ | 61.111 | 1,361 | Puts purchased | ||||||
2010 | 234,000 | $ | 88.088 | (1,557 | ) | Calls sold | |||||
2011 | 72,000 | $ | 93.109 | (699 | ) | Calls sold | |||||
2012 | 48,000 | $ | 90.314 | (620 | ) | Calls sold | |||||
$ | (849 | ) | |||||||||
Total net liability | $ | (66,987 | ) | ||||||||
(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 as a function of forward NYMEX natural gas, light crude and propane 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. |
NOTE 12 — FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership applies the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) to its financial instruments. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s 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 the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its respective outstanding derivative contracts (see Note 11). All of the Partnership’s and APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’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 and APL’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 APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution, and therefore are defined at Level 3. In accordance with SFAS No. 157, the following table represents the Partnership’s assets and liabilities recorded at fair value as of June 30, 2009 (in thousands):
Level 1 | Level 2 | Level 3 | Total | |||||||||||
Commodity-based derivatives | $ | — | $ | (59,919 | ) | $ | 1,103 | $ | (58,816 | ) | ||||
Interest rate swap-based derivatives | — | (8,715 | ) | — | (8,715 | ) | ||||||||
Total | $ | — | $ | (68,634 | ) | $ | 1,103 | $ | (67,531 | ) | ||||
APL’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 APL’s Level 3 derivative instruments as of June 30, 2009 (in thousands):
NGL Fixed Price Swaps | NGL Sales Options | Total | ||||||||||
Balance – December 31, 2008 | $ | 1,509 | $ | 12,316 | $ | 13,825 | ||||||
New options contracts | — | (1,024 | ) | (1,024 | ) | |||||||
Cash settlements from unrealized gain (loss)(1) | (4,215 | ) | (11,410 | ) | (15,625 | ) | ||||||
Cash settlements from other comprehensive income(1) | 3,700 | — | 3,700 | |||||||||
Net change in unrealized gain (loss)(2) | (1,567 | ) | (1,061 | ) | (2,628 | ) | ||||||
Deferred option premium recognition | — | 2,855 | 2,855 | |||||||||
Net change in other comprehensive loss | — | — | — | |||||||||
Balance – June 30, 2009 | $ | (573 | ) | $ | 1,676 | $ | 1,103 | |||||
(1) | Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations. |
(2) | Included within other loss, net on the Partnership’s consolidated statements of operations. |
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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 current assets and liabilities on the 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 June 30, 2009 and December 31, 2008, which consists principally of the Partnership’s subordinate loan with Atlas America, borrowings under the Partnership’s and APL’s credit facility, APL’s Term Loan and APL’s Senior Notes, was $1,141.0 million and $1,199.2 million, respectively, compared with the carrying amount of $1,307.3 million and $1,539.4 million, respectively. The APL term loan and APL Senior Notes were valued based upon available market data for similar issues. The carrying value of outstanding borrowings under the Partnership’s and APL’s 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):
June 30, 2009 | December 31, 2008 | ||||||
Credit facility | $ | 16,000 | $ | 46,000 | |||
Subordinate loan with Atlas America, Inc. | 15,000 | — | |||||
APL revolving credit facility | 322,000 | 302,000 | |||||
APL term loan | 459,885 | 707,180 | |||||
APL 8.125% Senior notes – due 2015 | 271,365 | 261,197 | |||||
APL 8.75% Senior notes – due 2018 | 223,050 | 223,050 | |||||
Total debt | 1,307,300 | 1,539,427 | |||||
Less current maturities | (31,000 | ) | — | ||||
Total long term debt | $ | 1,276,300 | $ | 1,539,427 | |||
Atlas Pipeline Holdings Credit Facility
At June 30, 2009, the Partnership, with Atlas Pipeline GP as guarantor, had $16.0 million outstanding under a credit facility with a syndicate of banks. On June 1, 2009, the Partnership entered into an amendment to its credit facility agreement which, among other changes:
• | required the Partnership to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility; |
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• | required the Partnership to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. The Partnership repaid $4.0 million of its outstanding credit facility borrowings on July 13, 2009 in accordance with the amendment through a subordinate loan with Atlas America. The Partnership may not borrow additional amounts under the credit facility or issue letters of credit; |
• | required the Partnership to use any of its “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires the Partnership to repay borrowings under the credit facility with the net proceeds of any sales of its common units in APL; |
• | eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL, and the interest coverage ratio (all as defined within the credit facility agreement); |
• | prohibits the Partnership from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits the Partnership to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and |
• | reduces the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rate on the outstanding credit facility borrowings at June 30, 2009 was 1.1%. |
Borrowings under the Partnership’s credit facility are secured by a first-priority lien on a security interest in all of the Partnership’s assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and the Partnership’s other subsidiaries (excluding APL and its subsidiaries). The Partnership’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to the Partnership’s unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of the Partnership’s property or assets, including the sale or transfer of interest in its subsidiaries. The Partnership is in compliance with these covenants as of June 30, 2009. The events which constitute an event of default under the Partnership’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against the Partnership in excess of a specified amount, a change of control of Atlas America, the Partnership’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.
On June 1, 2009, in connection with the Partnership’s amendment of the credit facility, Atlas America guaranteed the remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, the Partnership issued to Atlas America a promissory note which requires it to pay interest to Atlas America in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that the Partnership repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.
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Atlas Pipeline Holdings Subordinate Loan with Atlas America
On June 1, 2009, in connection with its amendment of the credit facility, the Partnership borrowed $15.0 million from Atlas America under a subordinate loan. The maturity date of the subordinate loan is generally the day following the date that the Partnership repays all outstanding borrowings under its credit facility. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable.
APL Term Loan and Revolving Credit Facility
At June 30, 2009, APL 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 APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at June 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at June 30, 2009 was 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $3.5 million was outstanding at June 30, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet.
On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:
• | increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest; |
• | for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum; |
• | increased the maximum ratios of funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain; |
• | instituted a maximum ratio of senior secured debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain; |
• | requires that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as defined in the credit agreement) of at least $50.0 million; |
• | generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter; |
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• | permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and |
• | instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio. |
In June 2008, APL entered into an amendment to the credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 11) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes. Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.
Borrowings under the credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and APL’s investment in the Laurel Mountain joint venture, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of June 30, 2009.
The events which constitute an event of default for the credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. The credit facility requires APL to maintain the following ratios:
Fiscal quarter ending: | Maximum Leverage Ratio | Maximum Senior Secured Leverage Ratio | Minimum Interest Coverage Ratio | |||
June 30, 2009 | 5.50x | 3.00x | 2.50x | |||
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 June 30, 2009, APL’s leverage ratio was 3.6 to 1.0, its senior secured leverage ratio was 2.2 to 1.0, and its interest coverage ratio was 4.2 to 1.0.
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APL Senior Notes
At June 30, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $4.1 million of unamortized discount as of June 30, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 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, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.
In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units (see Note 7). 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 the Partnership’s 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 APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of June 30, 2009.
In connection with the issuance of the APL 8.75% Senior Notes, APL entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the APL 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If APL did not meet the aforementioned deadline, the APL 8.75% Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that APL had caused the exchange offer to be consummated. On November 21, 2008, APL filed an exchange offer registration statement for the APL 8.75% Senior Notes with the Securities and Exchange Commission, which was declared effective on December 16, 2008. The exchange offer was consummated on January 21, 2009, thereby fulfilling all of the requirements of the APL 8.75% Senior Notes registration rights agreement by the specified dates.
NOTE 14 — COMMITMENTS AND CONTINGENCIES
APL 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 June 30, 2009, APL is committed to expend approximately $19.2 million on pipeline extensions, compressor station upgrades and processing facility upgrades.
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In January 2009, in the matter captioned “Elk City Oklahoma Pipeline, L.P. v. Northern Natural Gas Company”, (District Court of Tulsa County, Oklahoma), Elk City Oklahoma Pipeline, L.P. (“Elk City”), a subsidiary of APL, filed a petition against Northern Natural Gas Company (“NNG”), seeking a declaratory judgment related to the interpretation of a Purchase and Sale Agreement for certain pipeline and assets in Western Oklahoma which was entered into between the two parties on June 12, 2008 (the “PSA”). In March 2009, NNG filed a petition together with a motion for summary judgment alleging breach of the PSA for Elk City’s failure to complete the purchase and seeking specific performance or, alternatively, damages, in the matter captioned “Northern Natural Gas Company vs. Elk City Oklahoma Pipeline, L.P.”, (District Court of Tulsa County, Oklahoma). These matters were previously described in the Partnership’s quarterly report on Form 10-Q for the quarter ended March 31, 2009. Both matters were settled by agreement dated May 19, 2009. The settlement involved a monetary payment by Elk City, but does not require Elk City to purchase the pipeline assets. The amounts Elk City agreed to pay in connection with the settlement do not have a material impact on the Partnership’s financial condition or results of operations.
NOTE 15 — BENEFIT PLANS
The Partnership and APL follow the provisions of SFAS No. 123(R), “Share-Based Payment”, as revised
(“SFAS No. 123(R)”), for their stock compensation. Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.
Partnership’s Long-Term Incentive Plan. In November 2006, the Board of Directors approved and adopted the Partnership’s Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The LTIP is administered by a committee (the “LTIP Committee”), appointed by the Partnership’s board. Under the LTIP, phantom units and/or unit options may be granted, at the discretion of the LTIP Committee, to all or designated Participants, at the discretion of the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At June 30, 2009, the Partnership had 1,136,300 phantom units and unit options outstanding under the Partnership’s LTIP, with 962,650 phantom units and unit options available for grant.
Partnership Phantom Units.A phantom unit entitles a Participant to receive a common unit of the Partnership, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the Partnership’s LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of the Partnership. In tandem with phantom unit grants, the Partnership’s LTIP 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 such phantom unit is outstanding. The Partnership’s LTIP Committee will determine the vesting period for phantom units. Through June 30, 2009, phantom units granted under the LTIP generally will vest 25% three years from the date of grant and 100% four years from 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 Partnership’s LTIP 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. Of the phantom units outstanding under the Partnership’s LTIP at June 30, 2009, 44,425 units will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at June 30, 2009 include DERs granted to the Participants by the Partnership’s LTIP Committee. The amounts paid with respect to the Partnership’s LTIP DERs were $0.1 million for the three months ended June 30, 2008 and $14,000 and $0.2 million for the six months ended June 30, 2009 and 2008, respectively. There were no amounts paid with respect to the Partnership’s LTIP DERs for the three months ended June 30, 2009. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheet.
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The following table sets forth the Partnership’s LTIP phantom unit activity for the periods indicated:
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||
Outstanding, beginning of period | 181,300 | 225,475 | 226,300 | 220,825 | |||||||||
Granted(1) | — | — | — | 4,650 | |||||||||
Matured | — | — | — | — | |||||||||
Forfeited | — | — | (45,000 | ) | — | ||||||||
Outstanding, end of period(2) | 181,300 | 225,475 | 181,300 | 225,475 | |||||||||
Non-cash compensation expense recognized (in thousands) | $ | 291 | $ | 372 | $ | (17 | ) | $ | 738 | ||||
(1) | The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $32.28 for the six months ended June 30, 2008. There were no phantom units granted for the three months ended June 30, 2009 and 2008 and the six months ended June 30, 2009. |
(2) | The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 was $0.3 million. |
At June 30, 2009, the Partnership had approximately $1.2 million of unrecognized compensation expense related to unvested phantom units outstanding under its LTIP based upon the fair value of the awards.
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 Partnership’s LTIP Committee on the date of grant of the option. The Partnership’s LTIP Committee also shall determine how the exercise price may be paid by the Participant. The Partnership’s LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through June 30, 2009, unit options granted under the Partnership’s LTIP generally will vest 25% three years from the date of grant and 100% four years from 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 Partnership’s LTIP 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 213,750 unit options outstanding under the Partnership’s LTIP at June 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 June 30, | ||||||||||||
2009 | 2008 | |||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||
Outstanding, beginning of period | 955,000 | $ | 20.54 | 1,215,000 | $ | 22.56 | ||||||
Granted | — | — | — | — | ||||||||
Matured | — | — | — | — | ||||||||
Forfeited | — | — | — | — | ||||||||
Outstanding, end of period(1)(2) | 955,000 | $ | 20.54 | 1,215,000 | $ | 22.56 | ||||||
Options exercisable, end of period | — | — | — | — | ||||||||
Non-cash compensation expense recognized (in thousands) | $ | 222 | $ | 309 | ||||||||
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Six Months Ended June 30, | |||||||||||||
2009 | 2008 | ||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | ||||||||||
Outstanding, beginning of period | 1,215,000 | $ | 22.56 | 1,215,000 | $ | 22.56 | |||||||
Granted | 100,000 | $ | 3.24 | — | — | ||||||||
Matured | — | — | — | — | |||||||||
Forfeited | (360,000 | ) | $ | 22.56 | — | — | |||||||
Outstanding, end of period(1)(2) | 955,000 | $ | 20.54 | 1,215,000 | $ | 22.56 | |||||||
Options exercisable, end of period | — | — | — | — | |||||||||
Non-cash compensation expense recognized (in thousands) | $ | (351 | ) | $ | 619 | ||||||||
(1) | The weighted average remaining contractual lives for outstanding options at June 30, 2009 and 2008 were 7.6 years and 8.4 years, respectively. |
(2) | There was no intrinsic value of options outstanding at June 30, 2009. The aggregate intrinsic value of options outstanding at June 30, 2008 was approximately $13.3 million. |
At June 30, 2009, the Partnership had approximately $0.9 million of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s LTIP based upon the fair value of the awards.
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:
Three & Six Months Ended June 30, 2009 | |||
Expected dividend yield | 7.0 | % | |
Expected stock price volatility | 40 | % | |
Risk-free interest rate | 2.3 | % | |
Expected term (in years) | 6.9 |
APL Long-Term Incentive Plan
APL has a Long-Term Incentive Plan (“APL 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 APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by the Partnership’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units.
APL 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 APL LTIP Committee, cash equivalent to the fair market value of an APL common unit. In addition, the APL LTIP Committee may grant a participant a 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 APL makes on a common unit during the period the phantom unit is outstanding.
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A unit option entitles the grantee to purchase APL’s common limited partner units at an exercise price determined by the APL LTIP Committee at its discretion. The APL LTIP 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 Partnership, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through June 30, 2009, phantom units granted under the APL 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 APL LTIP 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 APL LTIP. Of the units outstanding under the APL LTIP at June 30, 2009, 29,376 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at June 30, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $11,000 and $0.2 million for the three months ended June 30, 2009 and 2008, respectively, and $0.1 million and $0.3 million for the six months ended June 30, 2009 and 2008, respectively. These amounts were recorded as reductions of non-controlling interest in APL on the Partnership’s consolidated balance sheet.
The following table sets forth the APL LTIP phantom unit activity for the periods indicated:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Outstanding, beginning of period | 101,929 | 171,087 | 126,565 | 129,746 | ||||||||||||
Granted(1) | 500 | 345 | 2,000 | 54,296 | ||||||||||||
Matured(2) | (25,208 | ) | (21,509 | ) | (35,094 | ) | (33,369 | ) | ||||||||
Forfeited | (500 | ) | — | (16,750 | ) | (750 | ) | |||||||||
Outstanding, end of period(3) | 76,721 | 149,923 | 76,721 | 149,923 | ||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 351 | $ | 697 | $ | 256 | $ | 1,183 | ||||||||
(1) | The weighted average prices for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, were $5.20 and $43.42 for awards granted for the three months ended June 30, 2009 and 2008, respectively, and $4.75 and $44.43 for awards granted for the six months ended June 30, 2009 and 2008, respectively. |
(2) | The intrinsic values for phantom unit awards vested during the three months ended June 30, 2009 and 2008 were $0.1 million and $0.9 million, respectively, and $0.2 million and $1.4 million during the six months ended June 30, 2009 and 2008, respectively. |
(3) | The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 was $0.6 million. |
At June 30, 2009, APL had approximately $1.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.
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APL Unit Options.A unit option entitles a Participant to receive a common unit of APL 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 APL’s common unit as determined by the APL LTIP Committee on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through June 30, 2009, unit options granted under APL’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 APL LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There are 25,000 unit options outstanding under the APL’s LTIP at June 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 June 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 | 100,000 | $ | 0.14 | — | — | |||||
Non-cash compensation expense recognized (in thousands) | $ | 2 | — | |||||||
Six Months Ended June 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) | $ | 4 | — | |||||||
(1) | The weighted average remaining contractual life for outstanding options at June 30, 2009 was 9.5 years. |
(2) | The aggregate intrinsic value of options outstanding at June 30, 2009 was $0.2 million. |
At June 30, 2009, APL had approximately $10,000 of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s LTIP based upon the fair value of the awards.
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APL 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:
Three and Six Months Ended June 30, 2009 | |||
Expected dividend yield | 11.0 | % | |
Expected stock price volatility | 20 | % | |
Risk-free interest rate | 2.2 | % | |
Expected term (in years) | 6.3 |
APL Incentive Compensation Agreements
APL 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 APL 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 APL assets during the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. APL’s 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 APL 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 APL would have been paid in cash.
As of December 31, 2008, APL recognized in full within its consolidated statements of operations the compensation expense associated with the vesting of awards issued under its incentive compensation agreements, therefore no compensation expense was recognized during the three and six months ended June 30, 2009. APL recognized compensation expense of $0.5 million and a reduction compensation expense of $2.8 million for the three and six months ended June 30, 2008 related to the vesting of awards under its incentive compensation agreements. The non-cash compensation expense adjustments for the three and six months ended June 30, 2008 were principally attributable to changes in APL’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at June 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 June 30, 2008. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method. During the six months ended June 30, 2009, APL issued 348,620 common units to the certain key employees covered under APL’s incentive compensation agreements. No additional common units will be issued with regard to these agreements.
APL Executive Incentive Plan
In June 2009, APL adopted an executive incentive plan (the “APL Plan”), which provides cash incentive awards to certain employees of APL, but not “Named Executive Officers” of APL, as defined under Securities and Exchange Commission regulations (the “APL Plan Participants”). The APL Plan is administered by a committee (the “APL Plan Committee”) appointed by APL’s chief executive officer. Under the APL Plan, cash bonus units (“Bonus Unit”) may be awarded to the APL Plan Participants at the discretion of the APL Plan Committee. A Bonus Unit entitles an APL Plan Participant to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the Bonus Unit. The APL Plan Committee will determine the vesting period for Bonus Units. Through June 30, 2009, Bonus Units granted under the APL Plan vest ratably over a three year period from the date of grant. Awards under the APL Plan will automatically vest upon a change of
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control of APL, as defined in the APL Plan, and vesting will terminate upon termination of employment. During the three and six months ended June 30, 2009, the APL Plan Committee granted 325,000 Bonus Units to APL Plan Participants under the APL Plan. Of the Bonus Units outstanding under the APL Plan at June 30, 2009, 107,250 Bonus Units will vest within the following twelve months. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value. During the three and six months ended June 30, 2009, the Partnership recognized $0.1 million of compensation expense within general and administrative expense on its consolidated statements of operations with respect to the vesting of these awards. At June 30, 2009, the Partnership has recognized $0.1 million within accrued liabilities on its consolidated balance sheet with regard to the awards, which represents their fair value at June 30, 2009.
NOTE 16 — RELATED PARTY TRANSACTIONS
Neither the Partnership nor APL directly employs any persons to manage or operate their businesses. These functions are provided by employees of Atlas America and its affiliates. Atlas Pipeline Holdings GP, LLC, the Partnership’s general partner, does not receive a management fee in connection with its management of APL, nor does Atlas Pipeline GP, the general partner of APL, receive a management fee in connection with its management of APL apart from its interest as general partner and its right to receive incentive distributions. APL reimburses the Partnership and its affiliates for compensation and benefits related to their employees who perform services for it based upon an estimate of the time spent by such persons on activities for APL. Other indirect costs, such as rent for offices, are allocated to APL by Atlas America based on the number of its employees who devote their time to activities on APL’s behalf.
APL’s partnership agreement provides that the Partnership will determine the costs and expenses that are allocable to APL in any reasonable manner determined by the Partnership at its sole discretion. APL reimbursed the Partnership and its affiliates $0.4 million and $1.4 million for the three months ended June 30, 2009 and 2008, respectively, and $0.8 million and $2.5 million for the six months ended June 30, 2009 and 2008, respectively, for compensation and benefits related to their employees. There were no direct reimbursements by APL to the Partnership and its affiliates for the three and six months ended June 30, 2009 and 2008. The Partnership believes that the method utilized in allocating costs to APL is reasonable.
NOTE 17 — SEGMENT INFORMATION
The Partnership’s assets primarily consist of its ownership interests in APL. APL 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 APL’s 49% ownership interest in Laurel Mountain, a joint venture to which APL contributed its natural gas transmission, gathering and processing assets located in eastern Ohio, western New York, and western Pennsylvania. APL 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 and its affiliates. These reportable segments reflect the way APL manages its operations.
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The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008(1) | 2009 | 2008(1) | |||||||||||||
Mid-Continent | ||||||||||||||||
Revenue: | ||||||||||||||||
Natural gas and liquids | $ | 176,674 | $ | 429,211 | $ | 331,453 | $ | 787,866 | ||||||||
Transportation, compression and other fees | 3,519 | 5,350 | 7,012 | 10,099 | ||||||||||||
Other loss, net | (15,711 | ) | (314,348 | ) | (10,635 | ) | (401,214 | ) | ||||||||
Total revenue and other loss, net | 164,482 | 120,213 | 327,830 | 396,751 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Natural gas and liquids | 129,595 | 349,206 | 264,151 | 622,550 | ||||||||||||
Plant operating | 14,128 | 14,831 | 27,951 | 29,766 | ||||||||||||
General and administrative | 4,956 | 6,514 | 13,270 | 8,663 | ||||||||||||
Depreciation and amortization | 21,619 | 18,868 | 42,368 | 37,533 | ||||||||||||
Total costs and expenses | 170,298 | 389,419 | 347,740 | 698,512 | ||||||||||||
Segment loss | $ | (5,816 | ) | $ | (269,206 | ) | $ | (19,910 | ) | $ | (301,761 | ) | ||||
Appalachia | ||||||||||||||||
Revenue: | ||||||||||||||||
Natural gas and liquids | $ | 214 | $ | 1,123 | $ | 585 | $ | 2,083 | ||||||||
Transportation, compression and other fees – affiliates | 6,429 | 11,421 | 16,497 | 20,580 | ||||||||||||
Transportation, compression and other fees – third parties | 462 | 321 | 843 | 568 | ||||||||||||
Equity income in joint venture | 710 | — | 710 | — | ||||||||||||
Gain on APL asset sale | 109,941 | — | 109,941 | — | ||||||||||||
Other income, net | 66 | 89 | 139 | 200 | ||||||||||||
Total revenue and other income, net | 117,822 | 12,954 | 128,715 | 23,431 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Natural gas and liquids | 81 | 505 | 270 | 987 | ||||||||||||
Transportation and compression | 2,791 | 2,645 | 6,122 | 4,959 | ||||||||||||
General and administrative | 792 | 1,523 | 1,974 | 3,007 | ||||||||||||
Depreciation and amortization | 1,380 | 1,544 | 3,299 | 2,926 | ||||||||||||
Total costs and expenses | 5,044 | 6,217 | 11,665 | 11,879 | ||||||||||||
Segment profit | $ | 112,778 | $ | 6,737 | $ | 117,050 | $ | 11,552 | ||||||||
Reconciliation of segment profit (loss) to net income (loss): | ||||||||||||||||
Segment profit (loss): | ||||||||||||||||
Mid-Continent | $ | (5,816 | ) | $ | (269,206 | ) | $ | (19,910 | ) | $ | (301,761 | ) | ||||
Appalachia | 112,778 | 6,737 | 117,050 | 11,552 | ||||||||||||
Total segment income (loss) | 106,962 | (262,469 | ) | 97,140 | (290,209 | ) | ||||||||||
Corporate general and administrative expenses | (1,761 | ) | (2,399 | ) | (2,406 | ) | (4,787 | ) | ||||||||
Interest expense(2) | (26,852 | ) | (20,204 | ) | (48,517 | ) | (41,396 | ) | ||||||||
Income (loss) from continuing operations | 78,349 | (285,072 | ) | 46,217 | (336,392 | ) | ||||||||||
Income from discontinued operations | 53,619 | 8,245 | 62,495 | 14,491 | ||||||||||||
Net income (loss) | $ | 131,968 | $ | (276,827 | ) | $ | 108,712 | $ | (321,901 | ) | ||||||
Capital Expenditures: | ||||||||||||||||
Mid-Continent | $ | 53,842 | $ | 57,669 | $ | 120,791 | $ | 119,156 | ||||||||
Appalachia | 4,457 | 8,512 | 9,703 | 22,898 | ||||||||||||
$ | 58,299 | $ | 66,181 | $ | 130,494 | $ | 142,054 | |||||||||
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4). |
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(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. |
June 30, 2009 | December 31, 2008(1) | |||||
Balance Sheet | ||||||
Total assets: | ||||||
Mid-Continent | $ | 1,993,188 | $ | 2,018,684 | ||
Appalachia | 145,266 | 114,166 | ||||
Discontinued operations | — | 255,606 | ||||
Corporate other | 32,506 | 30,528 | ||||
$ | 2,170,960 | $ | 2,418,984 | |||
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’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 June 30, | Six Months Ended June 30, | |||||||||||
2009 | 2008(1) | 2009 | 2008(1) | |||||||||
Natural gas and liquids: | ||||||||||||
Natural gas | $ | 57,922 | $ | 185,117 | $ | 134,498 | $ | 322,681 | ||||
NGLs | 98,228 | 211,033 | 164,522 | 409,726 | ||||||||
Condensate | 8,539 | 22,324 | 9,333 | 35,003 | ||||||||
Other(2) | 12,199 | 11,860 | 23,685 | 22,539 | ||||||||
Total | $ | 176,888 | $ | 430,334 | $ | 332,038 | $ | 789,949 | ||||
Transportation, compression and other fees: | ||||||||||||
Affiliates | $ | 6,429 | $ | 11,421 | $ | 16,497 | $ | 20,580 | ||||
Third Parties | 3,981 | 5,671 | 7,855 | 10,667 | ||||||||
Total | $ | 10,410 | $ | 17,092 | $ | 24,352 | $ | 31,247 | ||||
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’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 — SUBSEQUENT EVENTS
On July 13, 2009, APL 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 APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility.
On July 7, 2009, APL received an additional $2.5 million in cash upon the delivery of audited financial statements for the NOARK system assets to Spectra in connection with the completion of APL’s sale of its NOARK gas gathering and interstate pipeline system to Spectra for net proceeds of $292.0 million in cash, net of working capital adjustments (see Note 4).
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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 (NYSE: AHD). Our wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). APL is a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachian regions. Our cash generating assets currently consist solely of our interests in APL, a publicly traded Delaware limited partnership. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, their general partner, which owns at June 30, 2009:
• | a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL; |
• | all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), we, the holder of all the incentive distribution rights in APL, agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter (the “IDR Adjustment Agreement”). We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter; |
• | 5,754,253 common units of APL, representing approximately 12.0% of the outstanding common units of APL, or a 11.8% limited partner interest in APL; and |
• | 15,000 $1,000 par value 12.0% cumulative preferred limited partner units at June 30, 2009. |
While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.
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Our ownership of APL’s incentive distribution rights entitles us to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle us, subject to the IDR Adjustment Agreement, to receive the following:
• | 13.0% of all cash distributed in a quarter after each APL common unit has received $0.42 for that quarter; |
• | 23.0% of all cash distributed after each APL common unit has received $0.52 for that quarter; and |
• | 48.0% of all cash distributed after each APL common unit has received $0.60 for that quarter. |
These amounts are partially offset by our agreement to allocate up to $5.0 million of incentive distributions per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (see “—APL’s Partnership Distributions”).
We pay to our unitholders, on a quarterly basis, distributions equal to the cash we received from APL, less certain reserves for expenses and other uses of cash, including:
• | our general and administrative expenses, including expenses as a result of being a publicly traded partnership; |
• | capital contributions to maintain or increase our ownership interest in APL; and |
• | reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions. |
We did not declare a cash distribution for the quarters ended June 30, 2009 and March 31, 2009. On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes, prohibited us from paying any cash distributions on our equity while the credit facility is in effect (see “—Our Credit Facility”).
Atlas Pipeline Partners, L.P.
APL is a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol “APL”. APL’s principal business objective is to generate cash for distribution to its unitholders. APL is 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, APL is a leading provider of natural gas processing and treatment services in Oklahoma and Texas. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.
As of June 30, 2009, through its Mid-Continent operations, APL owns and operates:
• | 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 |
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• | 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 APL’s natural gas processing and treating plants or third party pipelines. |
As of June 30, 2009, APL’s Appalachia operations are conducted principally through its 49% ownership interest in Laurel Mountain Midstream, LLC (“Laurel Mountain” – see “Recent Events”), 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. APL also owns a 65 mile natural gas gathering system in northeastern Tennessee. Laurel Mountain gathers the majority all of the natural gas from wells operated by Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly traded company (NYSE: ATN).
Financial Presentation
We currently have no separate operating activities apart from those conducted by APL, and our cash flows consist of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own. The non-controlling limited partner interest in APL is reflected as an expense in our consolidated results of operations and as a liability on our consolidated balance sheet. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).
Recent Events
On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes:
• | required us to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility; |
• | required us to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. We repaid $4.0 million of our outstanding credit facility borrowings on July 13, 2009 in accordance with the amendment through a subordinate loan with Atlas America. We may not borrow additional amounts under the credit facility or issue letters of credit; |
• | required us to use any of our “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires us to repay borrowings under the credit facility with the net proceeds of any sales of our common units in APL; |
• | eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL, and the interest coverage ratio (all as defined within the credit facility agreement); |
• | prohibits us from paying any cash distributions on or redeeming any of our equity while the credit facility is in effect and permits us to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and |
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• | reduces the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. |
On June 1, 2009, in connection with our amendment of the credit facility, we borrowed $15.0 million from Atlas America under a subordinate loan. The maturity date of the subordinate loan is generally the day following the date that we repay all outstanding borrowings under our credit facility. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable.
On June 1, 2009, in connection with our amendment of the credit facility, Atlas America guaranteed the remaining balance outstanding under our credit facility under a guarantee agreement with the administrative agent of our credit facility. In consideration for this guarantee, we issued to Atlas America a promissory note which requires us to pay interest to Atlas America in an amount equal to the principal amount outstanding under our credit facility. The maturity date of the promissory note is the day following the date that we repay all outstanding borrowings under our credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.
On June 1, 2009, a newly created, wholly-owned subsidiary of ours, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash pursuant to a certificate of designation. We utilized the net proceeds from the issuance to reduce borrowings under our credit facility. Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for our common units. Distributions on the AHD Sub Preferred Units shall initially be paid in cash or by increasing the amount of the AHD Sub Preferred Unit equity by the amount of the distribution. However, under the terms of the certificate of designation, prior to the repayment of all outstanding borrowings under our credit facility, AHD Sub may only pay a cash distribution on the AHD Sub Preferred Units if we have received distributions on APL’s 12.0% Class B preferred units. After we have repaid all outstanding borrowings under our credit facility, all subsequent distributions declared by AHD Sub on the AHD Sub Preferred Units shall be paid in cash. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units, subject to certain limitations under the terms of the certificate of designation. As APL owns all of the outstanding AHD Sub Preferred Units in an amount equal to the Class B Preferred Units of APL that we own (see Note 7 to the consolidated financial statements in Item 1, “Financial Statements”), the amounts eliminate in consolidation of our consolidated balance sheet as of June 30, 2009.
On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which currently owns and operates APL’s former Appalachia Basin natural gas gathering system, excluding its Northern Tennessee operations. To Laurel Mountain, Williams contributed cash of $100.0 million, of which APL received approximately $87.8 million, net of working capital adjustments, and a note receivable of $25.5 million. APL contributed the Appalachia Basin natural gas gathering system and retained a 49% ownership interest in Laurel Mountain, which includes entitlement to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on the Partnership’s consolidated balance sheet at fair value and recognized a gain on sale of $109.9 million, including $79.7 million associated with the remeasurement of APL’s investment in Laurel Mountain to fair value. In addition, Atlas Energy sold to Laurel Mountain two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $10.0 million. Upon the completion of the transaction, Laurel Mountain entered into new gas gathering agreements with Atlas Energy which superseded the existing natural gas gathering
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agreements and omnibus agreement between APL and Atlas Energy. Under the new gas gathering agreement, Atlas Energy will be obligated to pay Laurel Mountain 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 partnerships’ gas). The new gathering agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system. APL’s ownership interest in Laurel Mountain has been recognized in accordance with the equity method of accounting within our consolidated financial statements. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see “—APL Term Loan and Revolving Credit Facility”).
On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:
• | increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest; |
• | for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum; |
• | increased the maximum ratios of funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain; |
• | instituted a maximum ratio of senior secured debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain; |
• | requires that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows APL to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and APL have minimum liquidity (as defined in the credit agreement) of at least $50.0 million; |
• | generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter; |
• | permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and |
• | instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio. |
On May 5, 2009, APL redeemed the remaining 5,000 APL 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 (see “APL Preferred Units”). Additionally on May 5, 2009, APL paid Sunlight a preferred dividend of $0.2 million, representing the quarterly dividend on the 5,000 APL Class A Preferred Units held by Sunlight prior to APL’s redemption. On April 13, 2009, APL converted 5,000 of the APL Class A Preferred Units held by Sunlight Capital, at Sunlight Capital’s option, into 1,465,653 APL
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common limited partner units in accordance with the terms of the agreement. On April 1, 2009, APL 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, pursuant to the terms of the agreement. Additionally on April 1, 2009, APL paid Sunlight a preferred dividend of $0.3 million, representing the quarterly dividend on the 10,000 APL Class A Preferred Units held by Sunlight prior to APL’s redemption.
On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE: SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see “—APL Term Loan and Revolving Credit Facility”). APL has recognized the sale of the NOARK system assets as discontinued operations within our consolidated financial statements.
Subsequent Events
On July 13, 2009, APL 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 APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility.
On July 7, 2009, APL received an additional $2.5 million in cash upon the delivery of audited financial statements for the NOARK system assets to Spectra in connection with the completion of APL’s sale of its NOARK gas gathering and interstate pipeline system to Spectra for net proceeds of $292.0 million in cash, net of working capital adjustments (see “—Recent Events”).
Contractual Revenue Arrangements
APL’s principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables that affect its revenue are:
• | the volumes of natural gas APL gathers, transports and processes which, in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and |
• | the transportation and processing fees APL receives which, in turn, depends upon the price of the natural gas and NGLs it transports and processes, which itself is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States. |
APL’s Mid-Continent segment revenue consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced NGLs, if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with APL’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. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.
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POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.
Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.
Revenue in APL’s Appalachia segment is principally recognized at the time the natural gas is transported through its gathering systems.
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.
APL faces competition for natural gas transportation and in obtaining natural gas supplies for its 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 APL’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, APL. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows APL to compete more effectively for new natural gas supplies in its regions of operations.
As a result of APL’s POP and keep-whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. APL believes 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, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which APL believes 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.
APL is 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 APL’s future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the
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value of APL’s assets and operations from such price risks. APL does not realize the full impact of commodity price changes because some of its 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 APL processes and sells, based on estimated unhedged market prices of $0.79 per gallon, $5.00 per mmbtu and $69.54 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin, excluding the effect of non-controlling interest in APL net income (loss), for the twelve-month period ending June 30, 2010 by approximately $23.4 million.
Currently, there is an unprecedented level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us and APL. These risks include the availability and costs associated with our and APL’s borrowing capabilities and APL’s raising additional capital, and an increase in the volatility of the price of our and APL’s common units. While we and APL have no definitive plans to access the capital markets, should we and APL 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.
Results of Operations
The following table illustrates selected volumetric information related to APL’s reportable segments for the periods indicated:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||
2009 | 2008 | 2009 | 2008 | |||||
Operating data(1): | ||||||||
Appalachia: | ||||||||
Average throughput volume – mcfd(2) | 107,428 | 84,475 | 103,003 | 80,054 | ||||
Mid-Continent: | ||||||||
Velma system: | ||||||||
Gathered gas volume – mcfd | 80,068 | 65,519 | 73,050 | 63,960 | ||||
Processed gas volume – mcfd | 77,300 | 62,148 | 70,625 | 61,008 | ||||
Residue gas volume – mcfd | 61,354 | 49,033 | 55,794 | 48,086 | ||||
NGL volume – bpd | 8,497 | 6,993 | 7,770 | 6,841 | ||||
Condensate volume – bpd | 416 | 296 | 381 | 277 | ||||
Elk City/Sweetwater system: | ||||||||
Gathered gas volume – mcfd | 221,192 | 292,544 | 237,445 | 298,961 | ||||
Processed gas volume – mcfd | 216,804 | 229,673 | 235,258 | 233,038 | ||||
Residue gas volume – mcfd | 196,613 | 207,859 | 214,228 | 210,495 | ||||
NGL volume – bpd | 11,581 | 10,452 | 11,650 | 10,565 | ||||
Condensate volume – bpd | 337 | 284 | 432 | 324 | ||||
Chaney Dell system: | ||||||||
Gathered gas volume – mcfd | 276,901 | 284,528 | 289,889 | 268,008 | ||||
Processed gas volume – mcfd | 219,129 | 256,835 | 223,468 | 252,348 | ||||
Residue gas volume – mcfd | 240,518 | 243,465 | 248,204 | 231,830 | ||||
NGL volume – bpd | 13,663 | 13,358 | 13,674 | 12,880 | ||||
Condensate volume – bpd | 909 | 855 | 918 | 781 | ||||
Midkiff/Benedum system: | ||||||||
Gathered gas volume – mcfd | 161,355 | 150,157 | 157,687 | 146,350 | ||||
Processed gas volume – mcfd | 150,111 | 141,240 | 148,094 | 138,947 | ||||
Residue gas volume – mcfd | 99,106 | 96,160 | 102,155 | 96,386 | ||||
NGL volume – bpd | 20,473 | 20,830 | 21,555 | 20,590 | ||||
Condensate volume – bpd | 1,533 | 1,567 | 1,163 | 1,144 |
(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 APL has a 49% ownership interest, for the period May 31 – June 30, 2009. |
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Financial Presentation
On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (see “—Recent Events”). 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 June 30, 2009 Compared to Three Months Ended June 30, 2008
Revenue.Natural gas and liquids revenue was $176.9 million for the three months ended June 30, 2009, a decrease of $253.4 million from $430.3 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from APL’s Chaney Dell system of $98.3 million, APL’s Midkiff/Benedum system of $72.4 million, APL’s Velma system of $42.5 million and APL’s Elk City/Sweetwater system of $39.3 million, which were all impacted principally by significantly lower average commodity prices in comparison to the prior year comparable period. Processed natural gas volume on the Elk City/Sweetwater system averaged 216.8 MMcfd for the three months ended June 30, 2009, a decrease of 5.6% from the comparable prior year period. However, NGL production volume for the Elk City/Sweetwater system was 11,581 bpd, an increase of 10.8% from the comparable prior year period, representing an increase in plant production efficiency. The Midkiff/Benedum system had processed natural gas volume of 150.1 MMcfd for the three months ended June 30, 2009, an increase of 6.3% compared to 141.2 MMcfd for the comparable prior year period. Processed natural gas volume averaged 77.3 MMcfd on the Velma system for the three months ended June 30, 2009, an increase of 24.4% from the comparable prior year period. The Velma system’s NGL production volume increased 21.5% from the comparable prior year period to 8,497 bpd. Processed natural gas volume on the Chaney Dell system was 219.1 MMcfd for the three months ended June 30, 2009, a decrease of 14.7% compared to 256.8 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 2.3% from the comparable prior year period to 13,663 bpd for the three months ended June 30, 2009. APL enters into derivative instruments solely to hedge its 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 Note 11 to the consolidated financial statements in Item 1, “Financial Statements”.
Transportation, compression and other fee revenue decreased to $10.4 million for the three months ended June 30, 2009 compared with $17.1 million for the comparable prior year period. This $6.7 million decrease was primarily due to a $4.9 million decrease from APL’s Appalachia system and a $1.7 million decrease from APL’s Chaney Dell system. The decrease from the Appalachia system was due to APL’s contribution of the majority of the system to Laurel Mountain, a joint venture in which APL has a 49% ownership interest, on May 31, 2009, after which APL has recognized its 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 $0.7 million for the three months ended June 30, 2009 represents APL’s ownership interest in the net income of Laurel Mountain, a joint venture in which APL owns a 49% interest (see “—Recent Events”), for the period from formation on May 31, 2009 through June 30, 2009.
Gain on asset sale of $109.9 million for the three months ended June 30, 2009 represents the gain recognized on APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system (see “—Recent Events”).
Other loss, net, including the impact of certain gains and losses recognized on derivatives, was a loss of $15.8 million for the three months ended June 30, 2009, which represents a favorable movement of $298.5 million from the comparable prior year period loss of $314.3 million. This favorable movement was due primarily to a $137.3 million favorable movement in non-cash mark-to-market adjustments on APL’s derivatives, the absence in the current year period of $115.8 million of net cash derivative
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expense related to APL’s early termination of a portion of its derivative contracts during June 2008 (see Note 11 to the consolidated financial statements in Item 1, “Financial Statements”) and a favorable movement of $53.5 million for non-cash derivative gains related to APL’s early termination of a portion of its derivative contracts, partially offset by a $5.8 million unfavorable movement related to cash settlements on APL’s derivatives that were not designated as hedges. The $137.3 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to the recognition of a $134.8 million loss during the three months ended June 30, 2008, which was due to an increase in forward crude oil market prices from March 31, 2008 to June 30, 2008 and their unfavorable mark-to-market impact on certain non-hedge derivative contracts APL had for production volumes in future periods. For example, average forward crude oil prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at June 30, 2008 were $140.26 per barrel, an increase of $43.32 per barrel from average forward crude oil market prices at March 31, 2008 of $96.94 per barrel. APL enters into derivative instruments solely to hedge its 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 $129.7 million for the three months ended June 30, 2009 represented a decrease of $220.0 million from the prior year comparable period due primarily to a significant decrease in APL’s average commodity prices in comparison to the prior year period. Plant operating expenses of $14.1 million for the three months ended June 30, 2009 represented a decrease of $0.7 million from the prior year comparable period due primarily to a $0.8 million decrease associated with APL’s Chaney Dell system resulting from lower operating and maintenance costs. Transportation and compression expenses increased slightly to $2.8 million for the three months ended June 30, 2009 compared with $2.6 million for the prior year comparable period due to higher APL Appalachia system operating and maintenance expenses as a result of increased capacity in comparison to the prior year period.
General and administrative expense, including amounts reimbursed to affiliates, decreased $3.1 million to $7.3 million for the three months ended June 30, 2009 compared with $10.4 million for the prior year comparable period. The decrease was primarily related to a $1.0 million decrease in executive management’s allocable time devoted to APL projects and a $1.0 million decrease in non-cash compensation expense.
Depreciation and amortization increased to $23.0 million for the three months ended June 30, 2009 compared with $20.4 million for the three months ended June 30, 2008 due primarily to APL’s expansion capital expenditures incurred subsequent to June 30, 2008.
Interest expense increased to $26.9 million for the three months ended June 30, 2009 as compared with $20.2 million for the comparable prior year period. This $6.7 million increase was primarily due to a $4.6 million increase in interest expense related to APL’s additional senior notes issued during June 2008 (see “—APL Senior Notes”), a $1.7 million increase in the amortization of deferred finance costs due principally to accelerated amortization associated with APL’s retirement of a portion of its term loan with the proceeds from the sale of its NOARK system (see “—Recent Events”) and a $1.6 million increase in interest expense associated with outstanding borrowings on APL’s revolving credit facility, partially offset by a $2.5 million decrease in interest expense associated with APL’s senior secured term loan primarily due to the repayment of $370.1 million of indebtedness since June 2008 (see “—APL Term Loan and Revolving Credit Facility”) and lower unhedged interest rates.
Income from discontinued operations consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system, which it sold on May 4, 2009 (see “—Recent Events”). Income from discontinued operations increased to $53.6 million for the three months ended June 30, 2009 compared with $8.2 million for the comparable prior year period. The increase was due to the $51.1 million gain APL recognized on the sale of the NOARK system, partially offset by a $5.7 million decrease in the operating results of the NOARK system due to the sale of the system on May 4, 2009.
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Income attributable to non-controlling interests decreased $2.4 million to a net income reduction of $0.7 million for the three months ended June 30, 2009 compared with $3.1 million for the comparable prior year period. This decrease was primarily due to lower net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect its 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.
Income attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, decreased $356.0 million to an expense of $114.3 million for the three months ended June 30, 2009 compared with income of $241.7 million for the comparable prior year period. This change was primarily due to an increase in APL’s net earnings between periods.
Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008
Revenue.Natural gas and liquids revenue was $332.0 million for the six months ended June 30, 2009, a decrease of $457.9 million from $789.9 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from APL’s Chaney Dell system of $168.1 million, APL’s Midkiff/Benedum system of $127.9 million, APL’s Elk City/Sweetwater system of $82.3 million and APL’s Velma system of $78.1 million, which were all impacted principally by significantly lower average commodity prices in comparison to the prior year comparable period. Processed natural gas volume on the Elk City/Sweetwater system averaged 235.3 MMcfd for the six months ended June 30, 2009, an increase of 1.0% from the comparable prior year period. However, NGL production volume for the Elk City/Sweetwater system was 11,650 bpd, an increase of 10.3% from the comparable prior year period, representing an increase in plant production efficiency. The Midkiff/Benedum system had processed natural gas volume of 148.1 MMcfd for the six months ended June 30, 2009, an increase of 6.6% compared to 138.9 MMcfd for the comparable prior year period. NGL production volume for the Midkiff/Benedum system was 21,555 bpd, an increase of 4.7% from the comparable prior year period. Processed natural gas volume averaged 70.6 MMcfd on the Velma system for the six months ended June 30, 2009, an increase of 15.8% from the comparable prior year period. The Velma system’s NGL production volume increased 13.6% from the comparable prior year period to 7,770 bpd. Processed natural gas volume on the Chaney Dell system was 223.5 MMcfd for the six months ended June 30, 2009, a decrease of 11.4% compared to 252.3 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 6.2% from the comparable prior year period to 13,674 bpd for the six months ended June 30, 2009. APL enters into derivative instruments solely to hedge its 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 Note 11 to the consolidated financial statements in Item 1, “Financial Statements”.
Transportation, compression and other fee revenue decreased to $24.4 million for the six months ended June 30, 2009 compared with $31.2 million for the comparable prior year period. This $6.8 million decrease was primarily due to a $3.8 million decrease from APL’s Appalachia system and a $3.1 million decrease from APL’s Chaney Dell system. The decrease from the Appalachia system was due to APL’s contribution of the majority of the system to Laurel Mountain, a joint venture in which APL has a 49% ownership interest, on May 31, 2009, after which APL has recognized its 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 $0.7 million for the six months ended June 30, 2009 represents APL’s ownership interest in the net income of Laurel Mountain, a joint venture in which APL owns a 49% interest (see “—Recent Events”), for the period from formation on May 31, 2009 through June 30, 2009.
Gain on asset sale of $109.9 million for the six months ended June 30, 2009 represents the gain recognized on APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system (see “—Recent Events”).
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Other loss, net, including the impact of certain gains and losses recognized on derivatives, was a loss of $10.7 million for the six months ended June 30, 2009, which represents a favorable movement of $390.3 million from the comparable prior year period loss of $401.0 million. This favorable movement was due primarily to a $180.0 million favorable movement in non-cash mark-to-market adjustments on APL’s derivatives, the absence in the current year period of $115.8 million of net cash derivative expense related to APL’s early termination of a portion of its derivative contracts during June 2008 (see Note 11 to the consolidated financial statements in Item 1, “Financial Statements”), a favorable movement of $65.6 million for non-cash derivative gains related to APL’s early termination of a portion of its derivative contracts and a $33.5 million favorable movement related to cash settlements on APL derivatives that were not designated as hedges. The $180.0 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to the recognition of a $211.7 million loss during the six months ended June 30, 2008, which was due to an increase in forward crude oil market prices from December 31, 2007 to June 30, 2008 and their unfavorable mark-to-market impact on certain non-hedge derivative contracts APL had for production volumes in future periods. For example, average forward crude oil prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at June 30, 2008 were $140.26 per barrel, an increase of $50.37 per barrel from average forward crude oil market prices at December 31, 2007 of $89.89 per barrel. APL enters into derivative instruments solely to hedge its 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 $264.4 million for the six months ended June 30, 2009 represented a decrease of $359.1 million from the prior year comparable period due primarily to a significant decrease in APL’s average commodity prices in comparison to the prior year period. Plant operating expenses of $28.0 million for the six months ended June 30, 2009 represented a decrease of $1.8 million from the prior year comparable period due primarily to a $1.4 million decrease associated with APL’s Midkiff/Benedum system resulting from lower operating and maintenance costs. Transportation and compression expenses increased slightly to $6.1 million for the six months ended June 30, 2009 compared with $5.0 million for the prior year comparable period due to higher APL Appalachia system operating and maintenance expenses as a result of increased capacity in comparison to the prior year period.
General and administrative expense, including amounts reimbursed to affiliates, increased $1.0 million to $17.5 million for the six months ended June 30, 2009 compared with $16.5 million for the prior year comparable period. The increase was primarily related to $2.8 million of non-recurring severance and other related costs incurred during the first quarter of 2009 for the termination of certain positions within APL’s Mid-Continent segment, partially offset by lower costs of managing our and APL’s operations.
Depreciation and amortization increased to $45.7 million for the six months ended June 30, 2009 compared with $40.5 million for the six months ended June 30, 2008 due primarily to APL’s expansion capital expenditures incurred subsequent to June 30, 2008.
Interest expense increased to $48.5 million for the six months ended June 30, 2009 as compared with $41.4 million for the comparable prior year period. This $7.1 million increase was primarily due to a $9.5 million increase in interest expense related to APL’s additional senior notes issued during June 2008 (see “—Senior Notes”), a $2.0 million increase in the amortization of deferred finance costs due principally to accelerated amortization associated with APL’s retirement of a portion of its term loan with the proceeds from the sale of its NOARK system (see “—Recent Events”) and a $2.0 million increase in interest expense associated with outstanding borrowings on APL’s revolving credit facility, partially offset by a $7.4 million decrease in interest expense associated with APL’s senior secured term loan primarily due to the repayment of $370.1 million of indebtedness since June 2008 (see “—APL Term Loan and Revolving Credit Facility”) and lower unhedged interest rates.
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Income from discontinued operations consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system, which it sold on May 4, 2009 (see “—Recent Events”). Income from discontinued operations increased to $62.5 million for the six months ended June 30, 2009 compared with $14.5 million for the comparable prior year period. The increase was due to the $51.1 million gain recognized on the sale of APL’s NOARK system, partially offset by a $3.1 million decrease in the operating results of the NOARK system due to the sale of the system on May 4, 2009.
Income attributable to non-controlling interests decreased $4.1 million to a net income reduction of $1.1 million for the six months ended June 30, 2009 compared with $5.2 million for the comparable prior year period. This decrease was primarily due to lower net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect its 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.
Income attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, decreased $379.8 million to an expense of $93.7 million for the three months ended June 30, 2009 compared with income of $286.1 million for the comparable prior year period. This change was primarily due to an increase in APL’s net earnings between periods.
Liquidity and Capital Resources
General
Our primary sources of liquidity are distributions received with respect to our ownership interests in APL and cash on hand. Our primary cash requirements are for our general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to APL to maintain or increase our ownership interest and quarterly distributions to our common unitholders. We expect to fund our general and administrative expenses through the retention of cash and our capital contributions to APL through the retention of cash from distributions received from APL. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see “—APL Term Loan and Revolving Credit Facility”) which, among other changes, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.
At June 30, 2009, we had $16.0 million outstanding under our credit facility (see “–– Our Credit Facility”) and were in compliance with our credit facility covenants. We believe that we will have sufficient liquid assets, including our ownership of 5.8 million limited partner units in APL, cash on hand and borrowing ability, including borrowings from Atlas America, to meet our financial commitments, debt service obligations and possible contingencies for at least the next twelve-month period. However, we are subject to business and other risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including other borrowings and the issuance of additional limited partner units and the sale of our ownership interests in APL.
APL’s primary sources of liquidity are cash generated from operations and borrowings under its credit facility. APL’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to its common unitholders and general partner. In general, we expect APL 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 |
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• | debt principal payments through additional borrowings as they become due or by the issuance of additional limited partner units or APL asset sales. |
At June 30, 2009, APL had $322.0 million of outstanding borrowings under its $380.0 million senior secured credit facility and $3.5 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $54.5 million of remaining committed capacity under its credit facility, subject to covenant limitations (see “—APL Term Loan and Revolving Credit Facility”). APL was in compliance with its credit facility covenants at June 30, 2009. We believe that APL will have sufficient liquid assets, cash from operations and borrowing capacity to meet its financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, APL is subject to business, operational and other risks that could adversely affect its cash flow. APL may need to supplement its cash generation with proceeds from financing activities, including borrowings under its credit facility and other borrowings, the issuance of additional limited partner units and the sale of its assets.
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 and APL’s ability to raise capital and reduce the amount of cash available to fund our and APL’s operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. We or APL cannot be certain that additional capital will be available to the extent required and on acceptable terms.
At June 30, 2009, we had a working capital deficit of $85.5 million compared with a working capital deficit of $43.8 million at December 31, 2008. This decrease in working capital was primarily due to a $40.4 million increase in net derivative liabilities, a $31.0 million increase in short-term debt obligations, a $22.9 million decrease in accounts receivable, and a $4.9 million increase in accrued liabilities, partially offset by a $45.2 million decrease in accounts payable and a $19.8 million decrease in accrued producer liabilities.
Cash Flows – Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008
Net cash provided by operating activities of continuing operations of $2.6 million for the six months ended June 30, 2009 represented an increase of $22.3 million from $19.7 million of cash used in operating activities of continuing operations for the prior year comparable period. The increase was derived principally by a $135.8 million decrease in cash flows from working capital changes, partially offset by a $111.7 million favorable movement in net earnings from continuing operations excluding non-cash charges. The increase in net earnings excluding non-cash charges was principally due to the absence in the current year period of $115.8 million of net cash derivative expense related to APL’s early termination of a portion of its derivative contracts during June 2008 (see Note 11 to the consolidated financial statements in Item 1, “Financial Statements”) and a $40.0 million decrease in cash distributions paid to our non-controlling interest holders. Non-cash charges which impacted net earnings from continuing operations excluding non-cash charges include a $167.8 million decrease in non-cash derivative losses and a $109.9 million decrease from the gain on the sale of APL’s Appalachia system assets, partially offset by a $5.2 million increase in depreciation and amortization expense. The movement in non-cash derivative losses resulted from decreases in commodity prices during the six months ended June 30, 2009 and their favorable impact on the fair value of derivative contracts APL has for future periods. The increase in depreciation and amortization principally resulted from depreciation associated with APL’s expansion capital expenditures incurred subsequent to June 30, 2008.
Net cash provided by operating activities of discontinued operations of $16.9 million for the six months ended June 30, 2009 represented a decrease of $5.0 million from $21.9 million for the prior year comparable period. The decrease was derived principally by an $11.9 million unfavorable movement in net earnings from discontinued operations excluding non-cash charges, partially offset by a $6.9 million increase in cash flows from working capital changes. The unfavorable movement in net earnings from discontinued operations excluding non-cash charges was due primarily to the sale of APL’s NOARK gas gathering and interstate pipeline system on May 4, 2009 (see —“Recent Events”).
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Net cash used in continuing investing activities was $45.0 million for the six months ended June 30, 2009, a decrease of $65.3 million from $110.3 million for the prior year comparable period. This decrease was principally due to the net proceeds of $87.8 million received from APL’s sale of its Appalachian system assets and an $11.6 million decrease in capital expenditures, partially offset by APL’s prior year receipt of $30.2 million cash reimbursement for state sales tax it paid on its prior year transaction to acquire the Chaney Dell and Midkiff/Benedum systems and APL’s prior year period receipt of $1.3 million in connection with a post-closing purchase price adjustment of its 2007 acquisition of the Chaney Dell and Midkiff/Benedum systems. See further discussion of capital expenditures under “—Capital Requirements”.
Net cash provided by discontinued investing activities was $290.6 million for the six months ended June 30, 2009, an increase of $305.7 million from $15.1 million of cash used in discontinued investing activities for the prior year comparable period. This increase was principally due to the net proceeds of $292.0 million received from the sale of APL’s NOARK gas gathering and interstate pipeline system (see —“Recent Events”), and a $13.5 million decrease in capital expenditures.
Net cash used in financing activities was $270.2 million for the six months ended June 30, 2009, a decrease of $543.8 million from $273.6 million of net cash provided by financing activities for the comparable prior year period. This decrease was principally due to the prior year $247.2 million of net proceeds from APL’s issuance of common units during June 2008, $244.9 million of net proceeds from APL’s issuance of 8.75% Senior Notes during June 2008 (see “—Term Loan and Revolving Credit Facility”), a $124.5 million increase in repayments of the outstanding principal balance on APL’s term loan, a $15.0 million redemption of APL’s outstanding Class A preferred units held by Sunlight Capital and the prior year $10.0 million of net proceeds from our issuance of common units during June 2008, partially offset by a $69.0 million net increase in borrowings under our and APL’s revolving credit facility, $15.0 million of proceeds from the receipt of a subordinate loan from Atlas America, Inc. (see “—Our Subordinate Loan with Atlas America”) and a $19.4 million decrease in cash distributions paid to our limited partners.
Capital Requirements
APL’s operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. APL’s 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 its existing operations. |
The following table summarizes APL’s maintenance and expansion capital expenditures related to continuing operations, excluding amounts paid for acquisitions, for the periods presented (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
2009 | 2008(1) | 2009 | 2008(1) | |||||||||
Maintenance capital expenditures | $ | 1,557 | $ | 1,971 | $ | 2,101 | $ | 3,486 | ||||
Expansion capital expenditures | 56,742 | 64,210 | 128,393 | 138,568 | ||||||||
Total | $ | 58,299 | $ | 66,181 | $ | 130,494 | $ | 142,054 | ||||
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see “—Recent Events”). |
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Expansion capital expenditures decreased to $56.7 million and $128.4 million for the three and six months ended June 30, 2009, respectively, compared with $64.2 million and $138.6 million for the prior year comparable periods. The decrease was due principally to APL’s construction of a 60MMcfd expansion of its Sweetwater processing plant and APL’s acquisition of a gathering system located in Tennessee during the six months ended June 30, 2008, partially offset by APL’s continued expansion of its gathering systems and upgrades to its processing facilities and compressors to accommodate new wells drilled in its service areas. The decrease in maintenance capital expenditures for the three and six months ended June 30, 2009 when compared with the comparable prior year period was due to fluctuations in the timing of APL’s scheduled maintenance activity. As of June 30, 2009, APL is committed to expend approximately $19.2 million on pipeline extensions, compressor station upgrades and processing facility upgrades. APL’s senior secured credit facility (see “—APL Term Loan and Revolving Credit Facility”) generally limits its annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter.
Our Credit Facility
At June 30, 2009, we, with Atlas Pipeline GP as guarantor, had $16.0 million outstanding under a revolving credit facility with a syndicate of banks. On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes:
• | required us to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility; |
• | required us to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. We repaid $4.0 million of our outstanding credit facility borrowings on July 13, 2009 in accordance with the amendment through a subordinate loan with Atlas America. We may not borrow additional amounts under the credit facility or issue letters of credit; |
• | required us to use any of our “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires us to repay borrowings under the credit facility with the net proceeds of any sales of our common units in APL; |
• | eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL, and the interest coverage ratio (all as defined within the credit facility agreement); |
• | prohibits us from paying any cash distributions on or redeeming any of our equity while the credit facility is in effect and permits us to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and |
• | reduces the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rate on the outstanding credit facility borrowings at June 30, 2009 was 1.1%. |
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Borrowings under our credit facility are secured by a first-priority lien on a security interest in all of our assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and our other subsidiaries (excluding APL and its subsidiaries). Our 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 would result from such distribution; or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interest in our subsidiaries. We are in compliance with these covenants as of June 30, 2009. The events which constitute an event of default under our credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against us in excess of a specified amount, a change of control of Atlas America, our general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.
On June 1, 2009, in connection with our amendment of the credit facility, Atlas America guaranteed the remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, we issued to Atlas America a promissory note which requires us to pay interest to Atlas America in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that we repay all outstanding borrowings under our credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.
Our Subordinate Loan with Atlas America
On June 1, 2009, in connection with our amendment of the credit facility, we borrowed $15.0 million from Atlas America under a subordinate loan. The maturity date of the subordinate loan is generally the day following the date that we repay all outstanding borrowings under the credit facility. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable.
Our Partnership Distributions
The board of directors of our general partner has adopted a cash distribution policy, pursuant to our partnership agreement, which requires that we distribute all of our available cash quarterly to our limited partners within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to, among other things:
• | provide for the proper conduct of our business; |
• | comply with applicable law, any of our debt instruments or other agreements; or |
• | provide funds for distributions to our unitholders for any one or more of 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. We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Our distributions to limited partners are not cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.
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On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes, prohibited us from paying any cash distributions on our equity while the credit facility is in effect (see “—Our Credit Facility”).
APL’s Partnership Distributions
APL’s partnership agreement requires that it distribute 100% of available cash to its common unitholders and general partner, our wholly-owned subsidiary, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of APL’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.
APL’s general partner is granted discretion by APL’s 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 APL’s general partner determines its 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 APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. During July 2007, we, as sole owner of APL’s general partner, agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.
On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see “—APL Term Loan and Revolving Credit Facility”) which, among other changes, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.
Off Balance Sheet Arrangements
As of June 30, 2009, our off balance sheet arrangements are limited to APL’s letters of credit outstanding of $3.5 million and its commitments to expend approximately $19.2 million on capital projects.
Our Equity Offerings
On June 1, 2009, a newly created, wholly-owned subsidiary of ours, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash pursuant to a certificate of designation. We utilized the net proceeds from the issuance to reduce borrowings under our senior secured credit facility (see “—Our Credit Facility”). Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for our common units. Distributions on the AHD Sub Preferred Units shall initially be paid in cash or by
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increasing the amount of the AHD Sub Preferred Unit equity by the amount of the amount of the distribution. However, under the terms of the certificate of designation, prior to the repayment of all outstanding borrowings under our credit facility, AHD Sub may only pay a cash distribution on the AHD Sub Preferred Units if we have received distributions on APL’s 12.0% Class B preferred units (see “—APL Preferred Units”). After we have repaid all outstanding borrowings under our credit facility, all subsequent distributions declared by AHD Sub on the AHD Sub Preferred Units shall be paid in cash. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units, subject to certain limitations under the terms of the certificate of designation. As APL owns all of the outstanding AHD Sub Preferred Units in an amount equal to the Class B Preferred Units of APL that we own, the amounts eliminate in consolidation of our consolidated balance sheet as of June 30, 2009.
In June 2008, we sold 308,109 common units through a private placement to Atlas America at a price of $32.50 per unit, for net proceeds of approximately $10.0 million. We utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements. Following our private placement, Atlas America had a 64.4% ownership interest in us.
APL Common Equity Offering
In June 2008, APL 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, APL sold 1,112,000 common units to Atlas America and 278,000 common units to us in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. APL also received a capital contribution from us of $5.4 million for it to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements.
APL Preferred Units
APL Class A Preferred Units
In January 2009, APL 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 “APL 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 APL Class A Preferred Units of April 1, 2009, (c) established Sunlight Capital’s new conversion option price of $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of its common units and (d) established a new price for APL’s call redemption right of $27.25.
The amendment to the preferred units certificate of designation also required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 (see “—APL Senior Notes”) to redeem 10,000 APL Class A Preferred Units. APL management estimated that the fair value of the $15.0 million 8.125% senior unsecured notes issued to redeem the APL 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, APL recorded the redemption by recognizing a $10.0 million reduction of non-controlling interest in APL 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 APL 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 APL 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.
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The amendment to the preferred units certificate of designation also required that (a) APL redeem 10,000 of the APL 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 APL Class A Preferred Units between April 1, 2009 and June 1, 2009, APL has the option of redeeming the APL Class A Preferred Units for cash at the stipulated liquidation value or converting the APL 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 APL Class A Preferred Units would have been required to be redeemed in cash, while APL had the option of redeeming the remaining 5,000 APL Class A Preferred Units in cash or converting the preferred units into its common limited partner units. On April 1, 2009, APL redeemed 10,000 of the APL 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, APL converted 5,000 of the APL Class A Preferred Units into 1,465,653 APL common units in accordance with the terms of the amended preferred units certificate of designation. On May 5, 2009, APL redeemed the remaining 5,000 APL 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.
APL Class B Preferred Units
In December 2008, APL sold 10,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “APL Class B Preferred Units”) to us for cash consideration of $1,000 per Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “APL Class B Preferred Units Certificate of Designation”). On March 30, 2009, we, pursuant to its right within the Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 APL Class B Preferred Units at Face Value. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes. The APL Class B Preferred Units receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The record date of determination for holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date of determination for APL’s common unit holders entitled to receive quarterly distributions. Additionally, on March 30, 2009, we and APL agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units are not convertible into APL common units. The amended APL Class B Preferred Units Certificate of Designation also gives APL the right at any time to redeem some or all of the outstanding APL Class B Preferred Units for cash at an amount equal to the APL 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 APL Class B Preferred Units or b) the number of remaining outstanding APL Class B Preferred Units. The cumulative sale of the APL Class B Preferred Units to us is exempt from the registration requirements of the Securities Act of 1933.
APL Term Loan and Revolving Credit Facility
At June 30, 2009, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at June 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at June 30, 2009 was 6.8%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $3.5 million was outstanding at June 30, 2009. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet.
On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:
• | increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest; |
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• | 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 ratios of funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain; |
• | instituted a maximum ratio of senior secured debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain; |
• | requires that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as defined in the credit agreement) of at least $50.0 million; |
• | generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter; |
• | permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and |
• | instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio. |
In June 2008, APL entered into an amendment to the credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 11 to the consolidated financial statements in Item 1, “Financial Statements”) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes (see “—APL Senior Notes”). Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.
Borrowings under the credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures and APL’s investment in the Laurel Mountain joint venture, and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of June 30, 2009.
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The events which constitute an event of default for the credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. The credit facility requires APL to maintain the following ratios:
Fiscal quarter ending: | Maximum Leverage Ratio | Maximum Senior Secured Leverage Ratio | Minimum Interest Coverage Ratio | |||
June 30, 2009 | 5.50x | 3.00x | 2.50x | |||
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 June 30, 2009, APL’s leverage ratio was 3.6 to 1.0, its senior secured leverage ratio was 2.2 to 1.0, and its interest coverage ratio was 4.2 to 1.0.
APL Senior Notes
At June 30, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $4.1 million of unamortized discount as of June 30, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL 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, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes in the aggregate are also subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.
In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units (see “—APL Preferred Units”). APL’s 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 APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL is in compliance with these covenants as of June 30, 2009.
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In connection with the issuance of the APL 8.75% Senior Notes, APL entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the APL 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If APL did not meet the aforementioned deadline, the APL 8.75% Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that APL had caused the exchange offer to be consummated. On November 21, 2008, APL filed an exchange offer registration statement for the APL 8.75% Senior Notes with the Securities and Exchange Commission, which was declared effective on December 16, 2008. The exchange offer was consummated on January 21, 2009, thereby fulfilling all of the requirements of the APL 8.75% Senior Notes registration rights agreement by the specified dates.
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. 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 June 30, 2009.
Fair Value of Financial Instruments
We apply the provisions of SFAS No. 157, “Fair Value Instruments” (“SFAS No. 157”), to our financial statements. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157 (1) creates a single definition of fair value, (2) establishes a hierarchy for measuring fair value, and (3) expands disclosure requirements about items measured at fair value. SFAS No. 157 does not change existing accounting rules governing what can or what must be recognized and reported at fair value in our financial statements, or disclosed at fair value in our notes to the financial statements. As a result, we will not be required to recognize any new assets or liabilities at fair value.
SFAS No. 157’s 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.
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We and APL use the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its respective outstanding derivative contracts (see Note 11 to the consolidated financial statements in Item 1, “Financial Statements”). All of our and APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. Our and APL’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 APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for APL’s NGL options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined as Level 3.
Recently Adopted Accounting Standards
In May 2009, the Financial Accounting Standards Board (“FASB”) issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 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. SFAS No. 165 requires 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. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. We adopted the requirements of SFAS No. 165 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 SFAS 165 does not change our current practices with respect to evaluating, recording and disclosing subsequent events.
In April 2009, the FASB issued Staff Position 157-4, “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” (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 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 FSP FAS 157-4 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 Staff Position 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2 and FAS 124-2”). FSP FAS 115-2 and FAS 124-2 change existing guidance for determining whether an impairment is other than temporary for debt securities. FSP FAS 115-2 and FAS 124-2 replaces the existing requirement that an entity’s management assess 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. FSP FAS 115-2 and FAS 124-2 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. FSP FAS 115-2 and FAS 124-2 are 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 FSP FAS 115-2 and FAS 124-2 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 Staff Position 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 APB 28-1 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
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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. FSP FAS 107-1 APL 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 107-1 APL 28-1 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 Staff Position 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141(R)-1”). FSP 141(R)-1 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 FASB Statement No. 5, “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss”. FSP 141(R)-1 also eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. FSP FAS 141(R)-1 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 of FSP 141(R)-1 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 the Emerging Issues Task Force’s (“EITF”) Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” 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. FSP EITF 03-6-1 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 of FSP EITF 03-6-1 on January 1, 2009 and its adoption did not have a material impact on our financial position and results of operations (see “—Net Income (Loss) Per Common Unit” in Note 2 to the consolidated financial statements in Item 1, “Financial Statements”). Prior-period net loss per common limited unit data presented has been adjusted retrospectively to conform to the provisions of FSP EITF 03-6-1.
In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 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 FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. Generally Accepted Accounting Principles. We adopted the requirements of FSP FAS 142-3 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 ratified the EITF consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF 07-4 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. EITF 07-4 also 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. Our adoption of EITF No. 07-4 on January 1, 2009 did not have a material impact on our financial position and results of operations.
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In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted the requirements of SFAS No. 161 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 in Item 1, “Financial Statements”).
In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish 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. SFAS No. 160 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, SFAS No. 160 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. SFAS No. 160 also requires that a 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 SFAS No. 160 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 the provisions of SFAS No. 160.
In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”), however 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. SFAS No. 141(R) 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, SFAS No. 141 (R) 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 the requirements of SFAS No. 141(R) 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 June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, 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 Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will apply the requirements of SFAS No. 168 to our financial statements for the interim period ending September 30, 2009 and we do not expect it to have a material impact to our financial position or results of operations or related disclosures.
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In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” and 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. SFAS No. 167 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. SFAS No. 167 is 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 the requirements of SFAS No. 167 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. As our assets currently consist solely of our ownership interests in APL, the following information principally encompasses APL’s exposure to market risks unless otherwise noted. 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 and APL’s market risk sensitive instruments were entered into for purposes other than trading.
General
All of our and APL’s assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.
We and APL 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 and APL 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 June 30, 2009. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our and APL’s business.
Current market conditions elevate our and APL’s concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us and APL, if any. The counterparties to APL’s commodity derivative contracts and our and APL’s interest-rate derivative contracts are banking institutions who also participate in our and APL’s revolving credit facility. The creditworthiness of our and APL’s counterparties is constantly monitored, and we and APL are not aware of any inability on the part of our respective counterparties to perform under our contracts.
Interest Rate Risk.At June 30, 2009, we had a credit facility with $16.0 million outstanding. The weighted average interest rate for these borrowings was 1.1% at June 30, 2009.
In May 2008, we entered into an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, we will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of our credit facility (see —“Our Credit Facility”), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is in effect at June 30, 2009 and expires on May 28, 2010.
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At June 30, 2009, APL had a $380.0 million senior secured revolving credit facility ($322.0 million outstanding). APL also had $459.9 million outstanding under its senior secured term loan at June 30, 2009. Borrowings under the credit facility bear interest, at APL’s option at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). On May 29, 2009, APL entered into an amendment to its 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 APL’s revolving credit facility borrowings was 6.8% at June 30, 2009, and the weighted average interest rate for the term loan borrowings was 6.8% at June 30, 2009.
At June 30, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL interest rate swap agreements are in effect as of June 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, APL discontinued hedge accounting for its interest rate derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives will be recognized immediately within other 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 and APL’s cumulative annual interest expense by $4.6 million.
Commodity Price Risk. APL is 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, APL receives fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, APL either receives 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 APL processes and sells, based on estimated unhedged market prices of $0.79 per gallon, $5.00 per mmbtu and $69.54 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin for the twelve-month period ending June 30, 2010, excluding the effect of non-controlling interests in APL net income (loss), by approximately $23.4 million.
We and APL use a number of different derivative instruments, principally swaps and options, in connection with our commodity price and interest rate risk management activities. APL 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. We and APL 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, APL 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.
We and APL apply the provisions of SFAS No. 133 to our derivative instruments. We and APL 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 the derivative contracts to the forecasted transactions. Under SFAS No. 133, we and APL can 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
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item being hedged, we and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by us and APL through the utilization of market data, will be recognized within other loss, net in our consolidated statements of operations. For APL’s 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 APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within other loss, net in our consolidated statements of operations as they occur.
Beginning July 1, 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. In addition, beginning May 29, 2009, APL discontinued hedge accounting for its existing interest rate derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives are recognized immediately within other 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 was 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 six months ended June 30, 2009 and year ended December 31 2008, APL 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 APL’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 six months ended June 30, 2009 and 2008, we recognized the following derivative activity related to APL’s termination of these derivative instruments within our consolidated statements of operations (amounts in thousands):
Early Termination of Derivative Contracts | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Net cash derivative expense included within other loss, net | $ | — | $ | (115,810 | ) | $ | (5,000 | ) | $ | (115,810 | ) | |||||
Net cash derivative expense included within natural gas and liquids revenue | — | (315 | ) | — | (315 | ) | ||||||||||
Net non-cash derivative income (expense) included within other loss, net | 7,117 | (46,345 | ) | 19,220 | (46,345 | ) | ||||||||||
Net non-cash derivative expense included within natural gas and liquids | (12,123 | ) | — | (34,067 | ) | — |
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The following table summarizes our and APL’s derivative activity for the periods indicated (amounts in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Loss from cash and non-cash settlement of qualifying hedge instruments(1) | $ | (7,327 | ) | $ | (33,152 | ) | $ | (27,502 | ) | $ | (50,795 | ) | ||||
Gain (loss) from change in market value of non-qualifying derivatives(2) | 2,509 | (136,736 | ) | (42,481 | ) | (207,932 | ) | |||||||||
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2) | — | 1,934 | 10,813 | (3,726 | ) | |||||||||||
Gain (loss) from cash and non-cash settlement of non-qualifying derivatives(2) | (21,105 | ) | (184,564 | ) | 13,390 | (196,489 | ) | |||||||||
Loss from cash settlement of interest rate derivatives(3) | (3,125 | ) | (207 | ) | (6,179 | ) | (207 | ) |
(1) | Included within natural gas and liquids revenue on our consolidated statements of operations. |
(2) | Included within other loss, net on our consolidated statements of operations. |
(3) | Included within interest expense on our consolidated statements of operations. |
The following table summarizes our and APL’s gross fair values of derivative instruments for the period indicated (amounts in thousands):
June 30, 2009 | |||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||
Derivatives designated as hedging instruments under SFAS No. 133: | |||||||||||
N/A | |||||||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | |||||||||||
Interest rate contracts | Current portion of derivative liability | $ | (8,715 | ) | |||||||
Commodity contracts | Current portion of derivative asset | $ | 1,815 | ||||||||
Commodity contracts | Long-term derivative asset | 1,606 | |||||||||
Commodity contracts | Current portion of derivative liability | 6,848 | Current portion of derivative liability | (56,337 | ) | ||||||
Commodity contracts | Long-term derivative liability | 3,151 | Long-term derivative liability | (15,899 | ) | ||||||
$ | 13,420 | $ | (80,951 | ) | |||||||
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The following table summarizes the gross effect of our and APL’s derivative instruments on our consolidated statements of operations for the period indicated (amounts in thousands):
Three months ended June 30, 2009 | ||||||||||||
Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | |||||||||
Derivatives in SFAS No. 133 cash flow hedging relationships: | ||||||||||||
N/A | ||||||||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | ||||||||||||
Interest rate contracts | $ | (3,125 | ) | Interest expense | $ | — | N/A | |||||
Commodity contracts(1) | (10,894 | ) | Natural gas and liquids revenue | (13,381 | ) | Other loss, net | ||||||
Commodity contracts(2) | — | N/A | (4,155 | ) | Other loss, net | |||||||
$ | (14,019 | ) | $ | (17,536 | ) | |||||||
(1) | Hedges previously designated as cash flow hedges |
(2) | Dedesignated cash flow hedges and non-designated hedges |
Six months ended June 30, 2009 | ||||||||||||
Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | |||||||||
Derivatives in SFAS No. 133 cash flow hedging relationships: | ||||||||||||
N/A | ||||||||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | ||||||||||||
Interest rate contracts | $ | (6,179 | ) | Interest expense | $ | — | N/A | |||||
Commodity contracts(1) | (26,864 | ) | Natural gas and liquids revenue | (22,908 | ) | Other loss, net | ||||||
Commodity contracts(2) | — | 35,665 | Other loss, net | |||||||||
$ | (33,043 | ) | $ | 12,757 | ||||||||
(1) | Hedges previously designated as cash flow hedges |
(2) | Dedesignated cash flow hedges and non-designated hedges |
As of June 30, 2009, we had the following interest rate 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) | |||||||||||
May 2008-May 2010 | $ | 25,000,000 | Pay 3.01% —Receive LIBOR | 2009 | $ | (323 | ) | ||||
2010 | (221 | ) | |||||||||
$ | (544 | ) |
(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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As of June 30, 2009, APL 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 | $ | (2,480 | ) | ||||
2010 | (351 | ) | |||||||||
$ | (2,831 | ) | |||||||||
April 2008-April 2010 | $ | 250,000,000 | Pay 3.14% —Receive LIBOR | 2009 | $ | (3,430 | ) | ||||
2010 | (1,910 | ) | |||||||||
$ | (5,340 | ) | |||||||||
Natural Gas Liquids Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(2) | ||||||
(gallons) | (per gallon) | (in thousands) | |||||||
2009 | 11,088,000 | $ | 0.745 | $ | (573 | ) | |||
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 | 234,000 | 13,185,000 | $ | 60.97 | $ | 1,234 | Puts purchased | ||||||
2009 | 1,055,400 | 59,081,820 | $ | 84.75 | (2,622 | ) | Calls sold | ||||||
2010 | 486,000 | 27,356,700 | $ | 61.24 | 3,838 | Puts purchased | |||||||
2010 | 3,127,500 | 213,088,050 | $ | 86.20 | (22,103 | ) | Calls sold | ||||||
2010 | 714,000 | 45,415,440 | $ | 132.17 | 708 | Calls purchased(5) | |||||||
2011 | 606,000 | 33,145,560 | $ | 100.70 | (4,065 | ) | Calls sold | ||||||
2011 | 252,000 | 13,547,520 | $ | 133.16 | 764 | Calls purchased(5) | |||||||
2012 | 450,000 | 25,893,000 | $ | 102.71 | (3,746 | ) | Calls sold | ||||||
2012 | 180,000 | 9,676,800 | $ | 134.27 | 801 | Calls purchased(5) | |||||||
$ | (25,191 | ) | |||||||||||
Natural Gas Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset(3) | |||||
(mmbtu)(6) | (per mmbtu) (6) | (in thousands) | ||||||
2009 | 240,000 | $ | 8.000 | $ | 866 | |||
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Natural Gas Basis Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset(3) | ||||||
(mmbtu)(6) | (per mmbtu)(6) | (in thousands) | |||||||
2009 | 2,460,000 | $ | (0.558 | ) | $ | 27 | |||
2010 | 2,220,000 | $ | (0.607 | ) | 124 | ||||
$ | 151 | ||||||||
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 | 5,160,000 | $ | 8.687 | $ | (22,156 | ) | ||||
2010 | 4,380,000 | $ | 8.635 | (12,414 | ) | |||||
$ | (34,570 | ) | ||||||||
Natural Gas Basis Purchases
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | |||||||
(mmbtu)(6) | (per mmbtu)(6) | (in thousands) | ||||||||
2009 | 7,380,000 | $ | (0.659 | ) | $ | (83 | ) | |||
2010 | 6,600,000 | $ | (0.590 | ) | (111 | ) | ||||
$ | (194 | ) | ||||||||
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 | $ | (40 | ) | 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 | 15,498,000 | $ | 0.767 | $ | 752 | Puts purchased | ||||
Isobutane 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 | 1,134,000 | $ | 0.969 | $ | 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 | 9,324,000 | $ | 0.964 | $ | 585 | Puts purchased | ||||
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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 | 5,796,000 | $ | 1.267 | $ | 358 | Puts purchased | ||||
Crude Oil Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | ||||||
(barrels) | (per barrel) | (in thousands) | |||||||
2009 | 15,000 | $ | 62.700 | $ | (131 | ) | |||
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 | 231,000 | $ | 63.017 | $ | 1,100 | Puts purchased | |||||
2009 | 153,000 | $ | 84.881 | (434 | ) | Calls sold | |||||
2010 | 174,000 | $ | 61.111 | 1,361 | Puts purchased | ||||||
2010 | 234,000 | $ | 88.088 | (1,557 | ) | Calls sold | |||||
2011 | 72,000 | $ | 93.109 | (699 | ) | Calls sold | |||||
2012 | 48,000 | $ | 90.314 | (620 | ) | Calls sold | |||||
$ | (849 | ) | |||||||||
Total net liability | $ | (66,987 | ) | ||||||||
(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 as a function of forward NYMEX natural gas, light crude and propane 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. |
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 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.
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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, as of June 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.
ITEM 1. | LEGAL PROCEEDINGS |
In January 2009, in the matter captioned “Elk City Oklahoma Pipeline, L.P. v. Northern Natural Gas Company”, (District Court of Tulsa County, Oklahoma), Elk City Oklahoma Pipeline, L.P. (“Elk City”), a subsidiary of ours, filed a petition against Northern Natural Gas Company (“NNG”), seeking a declaratory judgment related to the interpretation of a Purchase and Sale Agreement for certain pipeline and assets in Western Oklahoma which was entered into between the two parties on June 12, 2008 (the “PSA”). In March 2009, NNG filed a petition together with a motion for summary judgment alleging breach of the PSA for Elk City’s failure to complete the purchase and seeking specific performance or, alternatively, damages, in the matter captioned “Northern Natural Gas Company vs. Elk City Oklahoma Pipeline, L.P.”, (District Court of Tulsa County, Oklahoma). These matters were previously described in our quarterly report on Form 10-Q for the quarter ended March 31, 2009. Both matters were settled by agreement dated May 19, 2009. The settlement involved a monetary payment by Elk City, but does not require Elk City to purchase the pipeline assets. The amounts Elk City agreed to pay in connection with the settlement do not have a material impact on our financial condition or results of operations.
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 of Atlas Pipeline Holdings, L.P.(1) | |
3.2(a) | Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(2) | |
3.2(b) | Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(3) | |
4.1 | Specimen Certificate Representing Common Units(1) | |
10.1 | Certificate of Formation of Atlas Pipeline Holdings GP, LLC(1) | |
10.2(a) | Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(1) |
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10.2(b) | Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1) | |
10.2(c) | Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(4) | |
10.2(d) | Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.2(e) | Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.2(f) | Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.2(g) | Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership(7) | |
10.3 | Amended and Restated Certificate of Designation for 12% Cumulative Convertible Class B Preferred Units of Atlas Pipeline Partners, L.P. (7) | |
10.4 | Common Unit Purchase Agreement dated June 17, 2008, by and between Atlas America, Inc. and Atlas Pipeline Holdings, L.P.(5) | |
10.5 | Long-Term Incentive Plan(6) | |
10.6(a) | Revolving Credit Agreement dated as of July 26, 2006 by and among Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association and the lenders thereto(2) | |
10.6(b) | First Amendment to Revolving Credit Agreement dated as of June 1, 2009(8) | |
10.7 | Atlas Pipeline Holdings II, LLC Limited Liability Company Agreement(8) | |
10.8 | Promissory Note to Atlas America, Inc. dated June 1, 2009(8) | |
10.9 | Guaranty Note to Atlas America, Inc. dated June 1, 2009(8) | |
10.10 | 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(9) | |
10.11 | Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream, LLC dated as of June 1, 2009(9) | |
10.12(a) | Revolving Credit and Term Loan Agreement dated July 27, 2007 | |
10.12(b) | Amendment No. 1 and Agreement to the Revolving Credit and Term Loan Agreement, dated June 12, 2008 | |
10.12(c) | Amendment No. 2 to Revolving Credit and Term Loan Agreement, dated May 29, 2009 (10) | |
10.13 | Securities Purchase Agreement dated April 7, 2009, by and between Atlas Pipeline Mid-Continent, LLC and Spectra Energy Partners OLP, LP | |
31.1 | Rule 13(a)-14(a)/15(d)-14(a) Certification | |
31.2 | Rule 13(a)-14(a)/14(d)-14(a) Certification |
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32.1 | Section 1350 Certification | |
32.2 | Section 1350 Certification |
1 | Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999). |
2 | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2006. |
3 | Previously filed as an exhibit to current report on Form 8-K filed January 8, 2008. |
4 | Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007. |
5 | Previously filed as an exhibit to current report on Form 8-K filed June 23, 2008. |
6 | Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008. |
7 | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009. |
8 | Previously filed as an exhibit to current report on Form 8-K filed June 2, 2009. |
9 | Previously filed as an exhibit to current report on Form 8-K filed June 5, 2009. |
10 | Previously filed as an exhibit to current report on Form 8-K filed June 1, 2009. |
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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 HOLDINGS, L.P. | ||||||
By: Atlas Pipeline Holdings GP, LLC, its General Partner | ||||||
Date: August 10, 2009 | By: | /s/ EUGENE N. DUBAY | ||||
�� | Eugene N. Dubay | |||||
Chief Executive Officer, President, and Director of the General Partner | ||||||
Date: August 10, 2009 | By: | /s/ MATTHEW A. JONES | ||||
Matthew A. Jones | ||||||
Chief Financial Officer and Director of the General Partner | ||||||
Date: August 10, 2009 | By: | /s/ SEAN P. MCGRATH | ||||
Sean P. McGrath | ||||||
Chief Accounting Officer of the General Partner |
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