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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 March 31, 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 May 5, 2009 was 27,659,154.
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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
ON FORM 10-Q
PAGE | ||||
PART I. | FINANCIAL INFORMATION | |||
Item 1. | Financial Statements | |||
Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008 (Unaudited) | 3 | |||
Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008 (Unaudited) | 4 | |||
Consolidated Statement of Partners’ Capital for the Three Months Ended March 31, 2009 (Unaudited) | 5 | |||
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008 (Unaudited) | 6 | |||
7 | ||||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 39 | ||
Item 3. | 57 | |||
Item 4. | 64 | |||
PART II. | OTHER INFORMATION | |||
Item 1. | 64 | |||
Item 1A. | 65 | |||
Item 6. | 65 | |||
66 |
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
(Unaudited)
March 31, 2009 | December 31, 2008 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 2,533 | $ | 7,360 | ||||
Accounts receivable – affiliates | — | 341 | ||||||
Accounts receivable | 81,302 | 112,365 | ||||||
Current portion of derivative asset | — | 44,961 | ||||||
Prepaid expenses and other | 10,923 | 11,999 | ||||||
Total current assets | 94,758 | 177,026 | ||||||
Property, plant and equipment, net | 2,073,517 | 2,022,937 | ||||||
Intangible assets, net | 187,258 | 193,647 | ||||||
Other assets, net | 27,460 | 25,374 | ||||||
$ | 2,382,993 | $ | 2,418,984 | |||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable – affiliates | $ | 12,664 | $ | — | ||||
Accounts payable | 51,626 | 70,691 | ||||||
Accrued liabilities | 39,974 | 21,754 | ||||||
Current portion of derivative liability | 67,265 | 60,947 | ||||||
Preferred unit redemption obligation | 15,000 | — | ||||||
Accrued producer liabilities | 39,618 | 67,406 | ||||||
Total current liabilities | 226,147 | 220,798 | ||||||
Long-term derivative liability | 23,291 | 48,333 | ||||||
Long-term debt, less current portion | 1,571,403 | 1,539,427 | ||||||
Other long-term liability | 533 | 574 | ||||||
Commitments and contingencies | ||||||||
Partners’ capital: | ||||||||
Common limited partners’ interests | (11,138 | ) | (5,463 | ) | ||||
Accumulated other comprehensive loss | (14,721 | ) | (15,788 | ) | ||||
(25,859 | ) | (21,251 | ) | |||||
Non-controlling interests | (31,158 | ) | (32,337 | ) | ||||
Non-controlling interest in Atlas Pipeline Partners, L.P. | 618,636 | 663,440 | ||||||
Total partners’ capital | 561,619 | 609,852 | ||||||
$ | 2,382,993 | $ | 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 March 31, | ||||||||
2009 | 2008 | |||||||
Revenue: | ||||||||
Natural gas and liquids | $ | 158,618 | $ | 366,119 | ||||
Transportation, compression and other fees – affiliates | 10,068 | 9,159 | ||||||
Transportation, compression and other fees – third parties | 16,412 | 14,862 | ||||||
Other income (loss), net | 5,149 | (86,750 | ) | |||||
Total revenue and other income (loss), net | 190,247 | 303,390 | ||||||
Costs and expenses: | ||||||||
Natural gas and liquids | 138,059 | 276,664 | ||||||
Plant operating | 13,823 | 14,935 | ||||||
Transportation and compression | 4,767 | 3,812 | ||||||
General and administrative | 10,108 | 5,277 | ||||||
Compensation reimbursement – affiliates | 375 | 1,129 | ||||||
Depreciation and amortization | 24,680 | 21,844 | ||||||
Interest | 21,691 | 20,822 | ||||||
Asset impairment | — | 3,981 | ||||||
Total costs and expenses | 213,503 | 348,464 | ||||||
Net loss | (23,256 | ) | (45,074 | ) | ||||
Loss attributable to non-controlling interests | (469 | ) | (2,090 | ) | ||||
Income attributable to non-controlling interest in Atlas Pipeline Partners, L.P. | 20,642 | 44,344 | ||||||
Net loss attributable to common limited partners | $ | (3,083 | ) | $ | (2,820 | ) | ||
Net loss attributable to common limited partners per unit: | ||||||||
Basic | $ | (0.11 | ) | $ | (0.10 | ) | ||
Diluted | $ | (0.11 | ) | $ | (0.10 | ) | ||
Weighted average common limited partner units outstanding: | ||||||||
Basic | 27,659 | 27,350 | ||||||
Diluted | 27,659 | 27,350 | ||||||
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 THREE MONTHS ENDED MARCH 31, 2009
(in thousands, except unit data)
(Unaudited)
Common Limited Partners’ Capital | Accumulated Other Comprehensive | Non- Controlling | Non-Controlling Interest in Atlas | Total Partners’ Capital | ||||||||||||||||||
Units | $ | Income (Loss) | Interests | Pipeline Partners L.P. | (Deficit) | |||||||||||||||||
Balance at January 1, 2009 | 27,659,154 | $ | (5,463 | ) | $ | (15,788 | ) | $ | (32,337 | ) | $ | 663,440 | $ | 609,852 | ||||||||
Issuance of common limited partner units | — | (38 | ) | — | — | — | (38 | ) | ||||||||||||||
Distributions to non-controlling interests | — | — | — | 710 | (40,742 | ) | (40,032 | ) | ||||||||||||||
Unissued common units under interest holders | — | (880 | ) | — | — | — | (880 | ) | ||||||||||||||
Issuance of units under incentive plans | — | — | — | — | — | — | ||||||||||||||||
Distributions paid to common limited partners | — | (1,660 | ) | — | — | — | (1,660 | ) | ||||||||||||||
Distribution equivalent rights paid on unissued units under incentive plans | — | (14 | ) | — | — | — | (14 | ) | ||||||||||||||
Other comprehensive income | — | — | 1,067 | — | 16,580 | 17,647 | ||||||||||||||||
Net loss | — | (3,083 | ) | — | 469 | (20,642 | ) | (23,256 | ) | |||||||||||||
Balance at March 31, 2009 | 27,659,154 | $ | (11,138 | ) | $ | (14,721 | ) | $ | (31,158 | ) | $ | 618,636 | $ | 561,619 | ||||||||
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)
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net loss | $ | (23,256 | ) | $ | (45,074 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Distributions paid to non-controlling interest limited partners in Atlas Pipeline Partners, L.P. | (15,601 | ) | (30,958 | ) | ||||
Depreciation and amortization | 24,680 | 21,844 | ||||||
Asset impairment | — | 3,981 | ||||||
Non-cash loss on derivative value, net | 43,885 | 74,814 | ||||||
Non-cash compensation income | (973 | ) | (2,127 | ) | ||||
Amortization of deferred finance costs | 1,048 | 709 | ||||||
Net distributions to non-controlling interest holders | 710 | (413 | ) | |||||
Gain on asset sales and dispositions | — | (132 | ) | |||||
Change in operating assets and liabilities, net of effects of acquisitions: | ||||||||
Accounts receivable and prepaid expenses and other | 32,139 | (17,507 | ) | |||||
Accounts payable and accrued liabilities | (27,586 | ) | 22,157 | |||||
Accounts payable and accounts receivable – affiliates | 13,005 | (3,913 | ) | |||||
Net cash provided by operating activities | 48,051 | 23,381 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Net cash received in connection with acquisitions | — | 1,281 | ||||||
Capital expenditures | (72,913 | ) | (84,069 | ) | ||||
Other | (93 | ) | (251 | ) | ||||
Net cash used in investing activities | (73,006 | ) | (83,039 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Borrowings under Atlas Pipeline Partners, L.P. credit facility | 158,000 | 75,000 | ||||||
Repayments under Atlas Pipeline Partners, L.P. credit facility | (136,000 | ) | (15,000 | ) | ||||
Distributions paid to common limited partners | (1,660 | ) | (9,299 | ) | ||||
Other | (212 | ) | (204 | ) | ||||
Net cash provided by financing activities | 20,128 | 50,497 | ||||||
Net change in cash and cash equivalents | (4,827 | ) | (9,161 | ) | ||||
Cash and cash equivalents, beginning of period | 7,360 | 12,129 | ||||||
Cash and cash equivalents, end of period | $ | 2,533 | $ | 2,968 | ||||
See accompanying notes to consolidated financial statements
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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 March 31, 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 5) and 15,000 $1,000 par value Class B preferred limited partner units in APL (see Note 6). At March 31, 2009, APL had 46,173,866 common limited partnership units outstanding, including the 5,754,253 common units held by the Partnership, 20,000 $1,000 par value cumulative convertible Class A preferred limited partnership units outstanding and the 15,000 $1,000 par value Class B preferred units held by the Partnership (see Note 6).
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; |
• | 5,754,253 common units of APL, representing approximately 12.5% of the 46,173,866 outstanding common limited partnership units of APL, and |
• | 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units at March 31, 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 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.
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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 March 31, 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). Substantially all of the natural gas APL 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. 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. The results of operations for the three month period ended March 31, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.
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.
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
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beginning on June 15, 2009 and ending 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 options.
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 months ended March 31, 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 14), 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) 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 March 31, | ||||||||
2009 | 2008 | |||||||
Net loss | $ | (23,256 | ) | $ | (45,074 | ) | ||
Loss attributable to non-controlling interests | (469 | ) | (2,090 | ) | ||||
Income attributable to non-controlling interests – Atlas Pipeline Partners, L.P. | 20,642 | 44,344 | ||||||
Net loss attributable to common limited partners | (3,083 | ) | (2,820 | ) | ||||
Less: Net loss attributable to participating securities – phantom units(1) | (23 | ) | (23 | ) | ||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (3,060 | ) | $ | (2,797 | ) | ||
(1) | 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 loss attributable to common limited partners per unit is calculated by dividing net loss attributable to common limited partners, less 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 14). The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net loss attributable to common limited partners per unit with those used to compute diluted net loss attributable to common limited partners per unit (in thousands):
Three Months Ended March 31, | ||||
2009 | 2008 | |||
Weighted average common limited partners per unit - basic | 27,659 | 27,350 | ||
Add effect of dilutive option incentive awards(1) | — | — | ||
Weighted average common limited partners per unit - diluted | 27,659 | 27,350 | ||
(1) | For the three months ended March 31, 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. |
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 March 31, 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 7), 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.
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The outstanding APL Class A Preferred Units are reflected on the Partnership’s consolidated balance sheet as non-controlling interests in APL within partners’ capital.
During the year ended December 31, 2008, APL issued 56,227 common limited partner units under its Long-Term Incentive Plan (see Note 14). Additionally, during June 2008, the Partnership purchased 278,000, or 3.9%, of the aggregate 7,140,000 APL common limited partner units sold through a public offering and private placement (see Note 5). As a result of these transactions, the Partnership’s ownership percentage in APL, including its 2% interest as General Partner, was reduced to 14.3% from 15.8%. Pursuant to Securities and Exchange Commission Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary” (“SAB No. 51”), during the year ended December 31, 2008, the Partnership recorded a $3.4 million increase to its limited partners’ capital with a corresponding decrease to non-controlling interest in APL, 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.
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 4.8% and 6.7% for the three months ended March 31, 2009 and 2008, respectively, and the amount of interest capitalized was $1.4 million and $2.0 million for the three months ended March 31, 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 March 31, 2009 and December 31, 2008 (in thousands):
March 31, 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 | $ | (6,204 | ) | $ | (5,806 | ) | ||||
Customer relationships | (41,920 | ) | (35,929 | ) | ||||||
$ | (48,124 | ) | $ | (41,735 | ) | |||||
Net Carrying Amount: | ||||||||||
Customer contracts | $ | 6,606 | $ | 7,004 | ||||||
Customer relationships | 180,652 | 186,643 | ||||||||
$ | 187,258 | $ | 193,647 | |||||||
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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 March 31, 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.
Goodwill
The changes in the carrying amount of goodwill for the three months ended March 31, 2009 and 2008 were as follows (in thousands):
Three Months Ended March 31, | |||||||
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 | — | (2,275 | ) | ||||
Recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum acquisition | — | (30,206 | ) | ||||
Balance, end of period | $ | — | $ | 676,802 | |||
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 March 31, 2008.
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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 10). The following table sets forth the calculation of the Partnership’s comprehensive income (loss) (in thousands):
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
Net loss | $ | (23,256 | ) | $ | (45,074 | ) | ||
Loss attributable to non-controlling interests | (469 | ) | (2,090 | ) | ||||
Income attributable to non-controlling interests - Atlas Pipeline Partners, L.P. | 20,642 | 44,344 | ||||||
Net loss attributable to common limited partners | (3,083 | ) | (2,820 | ) | ||||
Other comprehensive income (loss): | ||||||||
Change in fair value of derivative instruments accounted for as cash flow hedges | (1,377 | ) | 18,585 | |||||
Changes in non-controlling interest related to items in other comprehensive income (loss) | (16,580 | ) | (29,381 | ) | ||||
Add: adjustment for realized losses reclassified to net loss | 19,024 | 17,643 | ||||||
Total other comprehensive income | 1,067 | 6,847 | ||||||
Comprehensive income (loss) | $ | (2,016 | ) | $ | 4,027 | |||
Revenue Recognition
Revenue in APL’s Appalachia segment is principally recognized at the time the natural gas is transported through the gathering systems. Under the terms of APL’s natural gas gathering agreements with Atlas Energy and its affiliates, APL receives fees for gathering natural gas from wells owned by Atlas Energy and by drilling investment partnerships sponsored by Atlas Energy. The fees received for the gathering services under the Atlas Energy agreements are generally the greater of 16% of the gross sales price for natural gas produced from the wells, or $0.35 to $0.40 per thousand cubic feet (“mcf”), depending on the ownership of the well. Substantially all natural gas gathering revenue in the Appalachia segment is derived from these agreements. Fees for transportation services provided to independent third parties whose wells are connected to APL’s Appalachia gathering systems are at separately negotiated prices.
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 APL’s FERC-regulated transmission pipeline is comprised of firm transportation rates, and to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation service is provided. 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.
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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 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.
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 March 31, 2009 and December 31, 2008 of $44.3 million and $54.8 million, respectively, which are included in accounts receivable and accounts receivable-affiliates within the Partnership’s consolidated balance sheets.
Recently Adopted Accounting Standards
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 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 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
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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 10).
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. 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.
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.
NOTE 3 – APL ASSET SALE AGREEMENT
On March 31, 2009, APL entered into an agreement with subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) to form a joint venture, Laurel Mountain Midstream, LLC (“Laurel Mountain”), that will own and operate APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. To the joint venture, Williams will contribute cash of $102.0 million, of which APL will receive approximately $90.0 million, and a note receivable of $25.5 million. APL will contribute its Appalachia Basin natural gas gathering system. APL will retain a 49% ownership interest in the joint venture, as well as preferred distribution rights relating to all payments on the note receivable. Williams will retain the remaining 51% ownership interest in the joint venture. In addition, ATN will sell to the joint venture two natural gas
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processing plants and associated pipelines located in Southwestern Pennsylvania for $12.0 million. Upon the completion of the sale of the APL Appalachia gathering systems to Laurel Mountain, Laurel Mountain will enter into new gas gathering agreements with Atlas Energy which will supersede the existing natural gas gathering agreements and omnibus agreement between APL and Atlas Energy. Under the proposed gas gathering agreement, Atlas Energy will be obligated to pay Laurel Mountain all of the gathering fees it collects from its 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 proposed 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 will account for its share of earnings associated with its ownership interest in Laurel Mountain under the equity method. The transaction is expected to close during the second quarter of 2009. APL will use the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 12).
NOTE 4 – ATLAS PIPELINE HOLDINGS PUBLIC OFFERING
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 5), which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 10). Following the Partnership’s private placement, Atlas America had a 64.4% ownership interest in the Partnership.
NOTE 5 – APL COMMON UNIT EQUITY OFFERINGS
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 10).
NOTE 6 – APL PREFERRED UNIT EQUITY OFFERINGS
APL Class A Preferred Units
At March 31, 2009, APL had 20,000 $1,000 par value 12.0% cumulative convertible Class A preferred units of limited partner interests (the “APL Class A Preferred Units”) outstanding that are held by Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates. In January 2009, APL and Sunlight Capital agreed to amend certain terms of the preferred unit certificate of designation, 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 12) 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
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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 in the Partnership’s consolidated statements of operations over the term of the notes based upon the effective interest rate method.
APL follows the provisions of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (“SFAS No. 150”). SFAS No. 150 states that financial instruments which are mandatorily redeemable shall be classified as a liability unless the redemption is required to occur only upon the liquidation or termination of the reporting entity. A financial instrument issued in the form of units is mandatorily redeemable if it embodies an unconditional obligation requiring the issuer to redeem the instrument by transferring assets at a specified or determinable date. The amendment of the preferred units certificate of designation required redemption of 15,000 of the APL Class A Preferred Units for cash in future periods. As such, APL reclassified $15.0 million of the $20.0 million of APL Class A Preferred Units outstanding at March 31, 2009 from non-controlling interest in APL to preferred unit redemption obligation on the Partnership’s consolidated balance sheet. In addition, in April 2009, APL and Sunlight Capital agreed that APL would convert 5,000 of the APL Class A Preferred Units into APL common units.
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.
APL recognized $0.5 million of preferred dividend cost for the three months ended March 31, 2009, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on its consolidated statements of operations. Of the $0.5 million of preferred dividend cost, $0.3 million was paid to Sunlight Capital on April 1, 2009 and $0.2 million was paid to Sunlight Capital on May 5, 2009. Sunlight Capital was entitled to receive dividends on the then-outstanding 40,000 Class A Preferred Units pro rata from the March 2008 commencement date. APL recognized $0.1 million of preferred dividend cost for the three months ended March 31, 2008, which is presented within non-controlling interest in APL on the Partnership’s consolidated statements of operations, and paid this dividend on May 15, 2008.
The outstanding APL Class A Preferred Units are reflected on the Partnership’s consolidated balance sheet as non-controlling interests in APL within partners’ capital.
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
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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 will receive a preferred dividend on the APL Class B Preferred Units of $0.5 million, which is to be paid on May 15, 2009, the same scheduled date as APL’s quarterly cash distribution to its common unitholders and the Partnership (see Note 7).
NOTE 7 – 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 March 31, 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 quarter ended March 31, 2009.
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. Distributions declared by APL for the period from January 1, 2008 through March 31, 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 |
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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.
On April 30, 2009, APL declared a cash distribution of $0.15 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2009. The $7.3 million distribution, including $0.1 million to the Partnership for its general partner interest, will be paid on May 15, 2009 to unitholders of record at the close of business on May 11, 2009.
NOTE 8 – PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment (in thousands):
March 31, 2009 | December 31, 2008 | Estimated Useful Lives in Years | ||||||||
Pipelines, processing and compression facilities | $ | 2,025,920 | $ | 1,959,379 | 15 – 40 | |||||
Rights of way | 180,179 | 178,114 | 20 – 40 | |||||||
Buildings | 8,968 | 8,968 | 40 | |||||||
Furniture and equipment | 9,486 | 9,387 | 3 – 7 | |||||||
Other | 14,066 | 13,812 | 3 – 10 | |||||||
2,238,619 | 2,169,660 | |||||||||
Less – accumulated depreciation | (165,102 | ) | (146,723 | ) | ||||||
$ | 2,073,517 | $ | 2,022,937 | |||||||
No impairment charges were recorded during the three months ended March 31, 2009. During the three months ended March 31, 2008, the Partnership recognized an impairment charge totaling $4.0 million within asset impairment on its consolidated statements of operations in connection with a write-off of costs related to an APL pipeline expansion project. The costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.
NOTE 9 – OTHER ASSETS
The following is a summary of other assets (in thousands):
March 31, 2009 | December 31, 2008 | |||||
Deferred finance costs, net of accumulated amortization of $18,623 and $17,575 at March 31, 2009 and December 31, 2008, respectively | $ | 25,780 | $ | 23,818 | ||
Security deposits | 1,605 | 1,419 | ||||
Other | 75 | 137 | ||||
$ | 27,460 | $ | 25,374 | |||
Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 12).
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NOTE 10 – 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 income (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 income (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.
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During the three months ended March 31, 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 months ended March 31, 2009 and 2008, the Partnership recognized the following derivative activity related to APL’s termination of these derivative instruments within its consolidated statement of operations (amounts in thousands):
Early Termination of Derivative Contracts for the Three Months Ended March 31, | |||||||
2009 | 2008 | ||||||
Net cash derivative expense included within other income (loss), net | $ | (5,000 | ) | $ | — | ||
Net cash derivative expense included within natural gas and liquids revenue | — | — | |||||
Net non-cash derivative income included within other income (loss), net | 12,103 | — | |||||
Net non-cash derivative expense included within natural gas and liquids | (21,944 | ) | — |
At March 31, 2009, the Partnership had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million, which were designated as cash flow hedges. 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 12), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of the Partnership’s floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement is effective at March 31, 2009 and expires on May 28, 2010.
At March 31, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million, which were designated as cash flow hedges. 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 (see Note 12), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements were effective as of March 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010.
The Partnership’s and APL’s derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. At March 31, 2009 and December 31, 2008, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $90.6 million and $64.3 million, respectively. Of the $14.7 million of net loss in accumulated other comprehensive loss within partners’ capital on the Partnership’s consolidated balance sheet at March 31, 2009, if the fair values of the instruments remain at current market values, the Partnership will reclassify $7.7 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period, consisting of $5.6 million of losses to natural gas and liquids revenue and $2.1 million of losses to interest expense. Aggregate losses of $7.0 million will be reclassified to the Partnership’s consolidated statements of operations in later periods, consisting of $6.9 million of losses to natural gas and liquids revenue and $0.1 million of losses to interest expense. 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):
March 31, 2009 | December 31, 2008 | |||||||
Current portion of derivative asset | $ | — | $ | 44,961 | ||||
Long-term hedge asset | — | — | ||||||
Current portion of derivative liability | (67,265 | ) | (60,947 | ) | ||||
Long-term derivative liability | (23,291 | ) | (48,333 | ) | ||||
$ | (90,556 | ) | $ | (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 March 31, | ||||||||
2009 | 2008 | |||||||
Loss from cash and non-cash settlement of qualifying hedge instruments(1) | $ | (20,175 | ) | $ | (17,643 | ) | ||
Loss from change in market value of non-qualifying derivatives(2) | (44,990 | ) | (71,196 | ) | ||||
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2) | 10,813 | (5,660 | ) | |||||
Gain (loss) from cash and non-cash settlement of non-qualifying derivatives(2) | 34,495 | (11,925 | ) | |||||
Loss from cash settlement of interest rate derivatives(3) | (3,055 | ) | — |
(1) | Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations. |
(2) | Included within other income (loss), net on the Partnership’s consolidated statements of operations. |
(3) | Included within interest expense on the Partnership’s consolidated statements of operations. |
The following table summarizes the Partnership’s and APL’s gross fair values of cumulative derivative instruments for the period indicated (amounts in thousands):
March 31, 2009 | |||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||
Balance Sheet | Fair Value | Balance Sheet | Fair Value | ||||||||
Derivatives designated as hedging instruments under SFAS No. 133: | |||||||||||
Interest rate contracts | Current portion of derivative asset | $ | — | Current portion of derivative liability | $ | (10,252 | ) | ||||
Interest rate contracts | Long-term derivative asset | — | Long-term derivative liability | (523 | ) | ||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | |||||||||||
Commodity contracts | Current portion of derivative liability | 3,977 | Current portion of derivative liability | (60,991 | ) | ||||||
Commodity contracts | Long-term derivative liability | 2,380 | Long-term derivative liability | (25,147 | ) | ||||||
$ | 6,357 | $ | (96,913 | ) | |||||||
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The following table summarizes the gross effect of the Partnership’s and APL’s cumulative derivative instruments on the Partnership’s consolidated statement of operations for the period indicated (amounts in thousands):
March 31, 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) | |||||||||
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships: | ||||||||||||
Interest rate contracts | $ | (3,055 | ) | Interest expense | $ | — | N/A | |||||
Derivatives not designated as hedging instruments under SFAS No. 133: | ||||||||||||
Commodity contracts(1) | $ | (15,970 | ) | Natural gas and liquids revenue | $ | (9,527 | ) | Other income (loss), net | ||||
Commodity contracts(2) | — | 39,820 | Other income (loss), net | |||||||||
$ | (19,025 | ) | $ | 30,293 | ||||||||
(1) | Hedges previously designated as cash flow hedges |
(2) | Dedesignated cash flow hedges and non-designated hedges |
As of March 31, 2009, the Partnership had the following interest rate derivatives:
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 | $ | (444 | ) | ||||
2010 | (204 | ) | |||||||||
$ | (648 | ) |
(1) | Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace. |
As of March 31, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:
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 | $ | (3,374 | ) | ||||
2010 | (304 | ) | |||||||||
$ | (3,678 | ) | |||||||||
April 2008-April 2010 | $ | 250,000,000 | Pay 3.14%—Receive LIBOR | 2009 | $ | (4,715 | ) | ||||
2010 | (1,734 | ) | |||||||||
$ | (6,449 | ) | |||||||||
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Natural Gas Liquids Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset(2) | |||||
(gallons) | (per gallon) | (in thousands) | ||||||
2009 | 13,230,000 | $ | 0.745 | $ | 1,579 | |||
Crude Oil Sales Options (associated with NGL volume)
Production Period Ended December 31, | Crude Volume | Associated NGL Volume | Average Crude Strike Price | Fair Value Asset/ (Liability)(1) | Option Type | ||||||||
(barrels) | (gallons) | (per barrel) | (in thousands) | ||||||||||
2009 | 152,100 | 13,542,984 | $ | 111.53 | $ | (11,171 | ) | Puts sold(4) | |||||
2009 | 152,100 | 13,542,984 | $ | 157.82 | — | Calls purchased(4) | |||||||
2009 | 1,588,500 | 88,643,058 | $ | 84.69 | (2,019 | ) | Calls sold | ||||||
2010 | 3,127,500 | 213,088,050 | $ | 86.20 | (13,035 | ) | Calls sold | ||||||
2010 | 714,000 | 45,415,440 | $ | 132.17 | 638 | Calls purchased(4) | |||||||
2011 | 606,000 | 33,145,560 | $ | 100.70 | (3,071 | ) | Calls sold | ||||||
2011 | 252,000 | 13,547,520 | $ | 133.16 | 665 | Calls purchased(4) | |||||||
2012 | 450,000 | 25,893,000 | $ | 102.71 | (2,822 | ) | Calls sold | ||||||
2012 | 180,000 | 9,676,800 | $ | 134.27 | 657 | Calls purchased(4) | |||||||
$ | (30,158 | ) | |||||||||||
Natural Gas Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset (3) | |||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | ||||||
2009 | 360,000 | $ | 8.000 | $ | 1,337 | |||
Natural Gas Basis Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset (3) | ||||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | |||||||
2009 | 3,690,000 | $ | (0.558 | ) | $ | 673 | |||
2010 | 2,220,000 | $ | (0.575 | ) | 301 | ||||
$ | 974 | ||||||||
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Natural Gas Purchases – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | |||||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | ||||||||
2009 | 7,740,000 | $ | 8.687 | $ | (34,069 | ) | ||||
2010 | 4,380,000 | $ | 8.635 | (12,806 | ) | |||||
$ | (46,875 | ) | ||||||||
Natural Gas Basis Purchases
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | |||||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | ||||||||
2009 | 11,070,000 | $ | (0.659 | ) | $ | (2,837 | ) | |||
2010 | 6,600,000 | $ | (0.560 | ) | (1,783 | ) | ||||
$ | (4,620 | ) | ||||||||
Ethane Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Asset(1) | Option Type | ||||||
(gallons) | (per gallon) | (in thousands) | ||||||||
2009 | 630,000 | $ | 0.340 | $ | 12 | Puts purchased | ||||
Isobutane Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Liability(1) | Option Type | |||||||
(gallons) | (per gallon) | (in thousands) | |||||||||
2009 | 126,000 | $ | 0.589 | $ | (10 | ) | Puts purchased | ||||
Normal Butane Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Liability(1) | Option Type | |||||||
(gallons) | (per gallon) | (in thousands) | |||||||||
2009 | 126,000 | $ | 0.577 | $ | (10 | ) | Puts purchased | ||||
Natural Gasoline Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Liability(1) | Option Type | |||||||
(gallons) | (per gallon) | (in thousands) | |||||||||
2009 | 126,000 | $ | 0.762 | $ | (10 | ) | Puts purchased | ||||
Crude Oil Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset(3) | |||||
(barrels) | (per barrel) | (in thousands) | ||||||
2009 | 24,000 | $ | 62.700 | $ | 206 | |||
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Crude Oil Sales Options
Production Period Ended December 31, | Volumes | Average Strike Price | Fair Value Liability (1) | Option Type | |||||||
(barrels) | (per barrel) | (in thousands) | |||||||||
2009 | 229,500 | $ | 84.802 | $ | (314 | ) | Calls sold | ||||
2010 | 234,000 | $ | 88.088 | (912 | ) | Calls sold | |||||
2011 | 72,000 | $ | 93.109 | (502 | ) | Calls sold | |||||
2012 | 48,000 | $ | 90.314 | (478 | ) | Calls sold | |||||
$ | (2,206 | ) | |||||||||
Total net liability | $ | (90,556 | ) | ||||||||
(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) | Puts sold and calls purchased for 2009 represent costless collars entered into by APL as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased for 2010 through 2012 to offset 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. |
(5) | Mmbtu represents million British Thermal Units. |
NOTE 11 – 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.
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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 10). 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 crude oil 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 crude oil 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 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 March 31, 2009 (in thousands):
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Commodity-based derivatives | $ | — | $ | (48,978 | ) | $ | (30,803 | ) | $ | (79,781 | ) | ||||
Interest rate swap-based derivatives | — | (10,775 | ) | — | (10,775 | ) | |||||||||
Total | $ | — | $ | (59,753 | ) | $ | (30,803 | ) | $ | (90,556 | ) | ||||
APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of March 31, 2009 (in thousands):
NGL Fixed Price Swaps | Crude Oil Sales Options (associated with NGL Volume) | Crude Oil Sales Options | NGL Sales Options | Total | ||||||||||||||||
Balance – December 31, 2008 | $ | 1,509 | $ | (15,867 | ) | $ | (7,569 | ) | $ | 12,316 | $ | (9,611 | ) | |||||||
New options contracts | 459 | — | — | — | 459 | |||||||||||||||
Cash settlements from unrealized gain (loss)(1) | (2,240 | ) | (30,189 | ) | (7,482 | ) | (11,410 | ) | (51,321 | ) | ||||||||||
Cash settlements from other comprehensive income(1) | 1,895 | 7,952 | 3,666 | — | 13,513 | |||||||||||||||
Net change in unrealized gain (loss)(2) | (44 | ) | 9,008 | 5,878 | (982 | ) | 13,860 | |||||||||||||
Deferred option premium recognition | — | (1,062 | ) | 3,301 | 58 | 2,297 | ||||||||||||||
Net change in other comprehensive loss | — | — | — | — | — | |||||||||||||||
Balance – March 31, 2009 | $ | 1,579 | $ | (30,158 | ) | $ | (2,206 | ) | $ | (18 | ) | $ | (30,803 | ) | ||||||
(1) | Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations. |
(2) | Included within other income (loss), net on the Partnership’s consolidated statements of operations. |
NOTE 12 – DEBT
Total debt consists of the following (in thousands):
March 31, 2009 | December 31, 2008 | |||||
Revolving credit facility | $ | 46,000 | $ | 46,000 | ||
APL revolving credit facility | 324,000 | 302,000 | ||||
APL term loan | 707,180 | 707,180 | ||||
APL 8.125% Senior notes – due 2015 | 271,173 | 261,197 | ||||
APL 8.75% Senior notes – due 2018 | 223,050 | 223,050 | ||||
Total long term debt | 1,571,403 | 1,539,427 | ||||
Less current maturities | — | — | ||||
Total long term debt | $ | 1,571,403 | $ | 1,539,427 | ||
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Atlas Pipeline Holdings Credit Facility
At March 31, 2009, the Partnership, with Atlas Pipeline GP as guarantor, had a $50.0 million revolving credit facility with a syndicate of banks, which had $46.0 million outstanding. The Partnership’s credit facility matures in April 2010 and bears interest, at its option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at March 31, 2009 was 3.2%. 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 a 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 interests in its subsidiaries. The Partnership is in compliance with these covenants as of March 31, 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. The Partnership’s credit facility requires it to maintain a combined leverage ratio, defined as the ratio of the sum of (i) the Partnership’s funded debt (as defined in its credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility) of not more than 5.5 to 1.0. In addition, the Partnership’s credit facility requires it to maintain a funded debt (as defined in its credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in its credit facility) of not less than 3.0 to 1.0. The Partnership’s credit facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable with respect to the last fiscal quarter in such period by APL to the Partnership in respect of the Partnership’s general partner interest, limited partner interest and incentive distribution rights in APL and (ii) the Partnership’s consolidated net income (as defined in its credit facility and as adjusted as provided in its credit facility). As of March 31, 2009, the Partnership’s combined leverage ratio was 5.1 to 1.0, its funded debt to EBITDA was 1.5 to 1.0, and its interest coverage ratio was 16.8 to 1.0.
The Partnership may borrow under its credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from the Partnership to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to its credit facility and (iii) for letters of credit.
APL Term Loan and Credit Facility
At March 31, 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 March 31, 2009 was 2.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at March 31, 2009 was 3.3%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $5.4 million was outstanding at March 31, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet.
In June 2008, APL entered into an amendment to its revolving credit facility and term loan agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to APL’s early termination of certain derivative contracts (see Note 10) in calculating its Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million
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of outstanding borrowings under the credit facility with proceeds from its issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “—Senior Notes”). Additionally, pursuant to this amendment, in June 2008, APL’s lenders increased their commitments for its revolving credit facility by $80.0 million to $380.0 million.
Borrowings under the APL 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 by the guaranty of each of its 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 in compliance with these covenants as of March 31, 2009. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt and equity issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days. In connection with entering into the credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank based upon the aggregate principal amount of the term loan outstanding, subject to adjustments as stated in the agreement. APL recorded an obligation for this fee of approximately $2.9 million within other assets and accrued liabilities on the Partnership’s consolidated balance sheet at March 31, 2009. APL has recognized this amount as a non-cash transaction within the Partnership’s consolidated statement of cashflows for the three months ended March 31, 2009.
The events which constitute an event of default for APL’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 APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires it to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.75 to 1.0. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of March 31, 2009, APL’s ratio of funded debt to EBITDA was 4.9 to 1.0 and its interest coverage ratio was 4.0 to 1.0.
APL is 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 Senior Notes
At March 31, 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 $270.5 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 $0.6 million of unamortized premium received as of March 31, 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.
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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 6). Management of the Partnership estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, the Partnership recognized a $5.0 million discount on the issuance of the Senior Notes, which will be 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 in 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 March 31, 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 13 – 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 March 31, 2009, APL is committed to expend approximately $56.7 million on pipeline extensions, compressor station upgrades and processing facility upgrades.
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’s, 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). Both matters are currently pending. APL believes that the claims are without merit and intend to pursue its action and defend against NNG’s claims. Additionally, APL believes that the ultimate resolution of these matters will not consequently have a material impact on the Partnership’s financial position and results of operations.
NOTE 14 – STOCK COMPENSATION
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.
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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 us. 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 March 31, 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 March 31, 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 March 31, 2009, 44,425 units will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at March 31, 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 $14,000 and $0.1 million for the three months ended March 31, 2009 and 2008, respectively. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheet.
The following table sets forth the Partnership’s LTIP phantom unit activity for the periods indicated:
Three Months Ended March 31, | |||||||
2009 | 2008 | ||||||
Outstanding, beginning of period | 226,300 | 220,825 | |||||
Granted(1) | — | 4,650 | |||||
Matured(2) | — | — | |||||
Forfeited | (45,000 | ) | — | ||||
Outstanding, end of period(3) | 181,300 | 225,475 | |||||
Non-cash compensation (income) expense recognized (in thousands) | $ | (308 | ) | $ | 366 | ||
(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 awards granted for the three months ended March 31, 2008. There were no awards granted during the three months ended March 31, 2009. |
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(2) | There were no phantom units exercised for the three months ended March 31, 2009 and 2008, respectively. |
(3) | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2009 is $0.3 million. |
At March 31, 2009, the Partnership had approximately $1.5 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 March 31, 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 March 31, 2009 that will vest within the following twelve months. The following table sets forth the LTIP unit option activity for the periods indicated:
For the Three Months Ended March 31, | |||||||||||||
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(3) | — | — | — | — | |||||||||
Weighted average fair value of unit options per unit granted during the period | 100,000 | $ | 0.61 | — | — | ||||||||
Non-cash compensation (income) expense recognized ( in thousands) | $ | (573 | ) | $ | 309 | ||||||||
(1) | The weighted average remaining contractual lives for outstanding options at March 31, 2009 and 2008 were 7.8 years and 8.6 years, respectively. |
(2) | There was no intrinsic value of options outstanding at March 31, 2009. The aggregate intrinsic value of options outstanding at March 31, 2008 was approximately $5.6 million. |
(3) | There were no options exercised during the three months ended March 31, 2009 and 2008, respectively. |
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At March 31, 2009, the Partnership had approximately $1.2 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 Months Ended March 31, 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. 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 March 31, 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 March 31, 2009, 31,607 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at March 31, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.1 million for the three months ended March 31, 2009 and 2008, respectively. These amounts were recorded as reductions of non-controlling interest in APL on the Partnership’s consolidated balance sheet.
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The following table sets forth the APL LTIP phantom unit activity for the periods indicated:
Three Months Ended March 31, | ||||||||
2009 | 2008 | |||||||
Outstanding, beginning of period | 126,565 | 129,746 | ||||||
Granted(1) | 1,500 | 53,951 | ||||||
Matured(2) | (9,886 | ) | (11,860 | ) | ||||
Forfeited | (16,250 | ) | (750 | ) | ||||
Outstanding, end of period(3) | 101,929 | 171,087 | ||||||
Non-cash compensation (income) expense recognized (in thousands) | $ | (95 | ) | $ | 486 | |||
(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 $4.60 and $44.44 for awards granted for the three months ended March 31, 2009 and 2008, respectively. |
(2) | The intrinsic values for phantom unit awards exercised during the three months ended March 31, 2009 and 2008 were $0.1 million and $0.2 million, respectively. |
(3) | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2009 was $0.4 million. |
At March 31, 2009, APL had approximately $1.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.
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 March 31, 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 March 31, 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 March 31, | |||||||||||
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(3) | — | — | — | — | |||||||
Weighted average fair value of unit options per unit granted during the period | 100,000 | $ | 0.14 | — | — | ||||||
Non-cash compensation expense recognized (in thousands) | $ | 2 | $ | — | |||||||
(1) | The weighted average remaining contractual life for outstanding options at March 31, 2009 was 9.8 years. |
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(2) | There was no aggregate intrinsic value of options outstanding at March 31, 2009. |
(3) | There were no options exercised during the three months ended March 31, 2009 and 2008, respectively. |
At March 31, 2009, APL had approximately $12,000 of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s LTIP based upon the fair value of the awards.
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 Months Ended March 31, 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 months ended March 31, 2009. APL recognized a reduction of compensation expense of $3.3 million for the three months ended March 31, 2008 related to the vesting of awards under its incentive compensation agreements. The non-cash compensation expense adjustments for the three months ended March 31, 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 March 31, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through March 31, 2008. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method. During the three months ended March 31, 2009, APL issued 209,172 common units to the certain key employees covered under APL’s incentive compensation agreements. APL will issue an additional 139,448 common units during the second quarter 2009 to fulfill its obligations under the terms of the agreements. No additional common units will be issued with regard to these agreements.
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NOTE 15 – 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 $1.1 million for the three months ended March 31, 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 months ended March 31, 2009 and 2008. The Partnership believes that the method utilized in allocating costs to APL is reasonable.
Under an agreement between APL and Atlas Energy, Atlas Energy must construct up to 2,500 feet of sales lines from its existing wells in the Appalachian region to a point of connection to APL’s gathering systems. APL must, at its own cost, extend its system to connect to any such lines within 1,000 feet of its gathering systems. With respect to wells to be drilled by Atlas Energy that will be more than 3,500 feet from APL’s gathering systems, APL has various options to connect those wells to its gathering systems at its own cost.
NOTE 16 – 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 located in the Appalachian Basin area (“Appalachia”) of eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee, and transmission, gathering and processing located in the Mid-Continent area (“Mid-Continent”) of primarily Oklahoma, northern and western Texas, the Texas Panhandle, Arkansas, southern Kansas and southeastern Missouri. Appalachia revenues are principally based on contractual arrangements with Atlas Energy and its affiliates. Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs and transport of natural gas. 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 March 31, | ||||||||
2009 | 2008 | |||||||
Mid-Continent | ||||||||
Revenue: | ||||||||
Natural gas and liquids | $ | 158,247 | $ | 365,159 | ||||
Transportation, compression and other fees | 16,031 | 14,615 | ||||||
Other income (loss), net | 5,075 | (86,865 | ) | |||||
Total revenue and other income (loss), net | 179,353 | 292,909 | ||||||
Costs and expenses: | ||||||||
Natural gas and liquids | 137,870 | 276,182 | ||||||
Plant operating | 13,823 | 14,935 | ||||||
Transportation and compression | 1,436 | 1,498 | ||||||
General and administrative | 8,655 | 2,530 | ||||||
Depreciation and amortization | 22,761 | 20,462 | ||||||
Asset impairment | — | 3,981 | ||||||
Total costs and expenses | 184,545 | 319,588 | ||||||
Segment loss | $ | (5,192 | ) | $ | (26,679 | ) | ||
Appalachia | ||||||||
Revenue: | ||||||||
Natural gas and liquids | $ | 371 | $ | 960 | ||||
Transportation, compression and other fees – affiliates | 10,068 | 9,159 | ||||||
Transportation, compression and other fees – third parties | 381 | 247 | ||||||
Other income, net | 73 | 111 | ||||||
Total revenue and other income, net | 10,893 | 10,477 | ||||||
Costs and expenses: | ||||||||
Natural gas and liquids | 189 | 482 | ||||||
Transportation and compression | 3,331 | 2,314 | ||||||
General and administrative | 1,182 | 1,484 | ||||||
Depreciation and amortization | 1,919 | 1,382 | ||||||
Total costs and expenses | 6,621 | 5,662 | ||||||
Segment profit | $ | 4,272 | $ | 4,815 | ||||
Reconciliation of segment profit (loss) to net loss: | ||||||||
Segment profit (loss): | ||||||||
Mid-Continent | $ | (5,192 | ) | $ | (26,679 | ) | ||
Appalachia | 4,272 | 4,815 | ||||||
Total segment loss | (920 | ) | (21,864 | ) | ||||
Corporate general and administrative expenses | (645 | ) | (2,388 | ) | ||||
Interest expense(1) | (21,691 | ) | (20,822 | ) | ||||
Net loss | $ | (23,256 | ) | $ | (45,074 | ) | ||
Capital Expenditures: | ||||||||
Mid-Continent | $ | 67,667 | $ | 69,683 | ||||
Appalachia | 5,246 | 14,386 | ||||||
$ | 72,913 | 84,069 | ||||||
(1) | 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. |
March 31, 2009 | December 31, 2008 | |||||
Balance Sheet | ||||||
Total assets: | ||||||
Mid-Continent | $ | 2,237,221 | $ | 2,274,290 | ||
Appalachia | 117,587 | 114,166 | ||||
Corporate other | 28,185 | 30,528 | ||||
$ | 2,382,993 | $ | 2,418,984 | |||
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The following tables summarize the Partnership’s total revenues by product or service for the periods indicated (in thousands):
Three Months Ended March 31, | ||||||
2009 | 2008 | |||||
Natural gas and liquids: | ||||||
Natural gas | $ | 77,598 | $ | 139,783 | ||
NGLs | 66,294 | 198,693 | ||||
Condensate | 794 | 12,680 | ||||
Other(1) | 13,932 | 14,963 | ||||
Total | $ | 158,618 | $ | 366,119 | ||
Transportation, compression and other fees: | ||||||
Affiliates | $ | 10,068 | $ | 9,159 | ||
Third parties | 16,412 | 14,862 | ||||
Total | $ | 26,480 | $ | 24,021 | ||
(1) | Includes treatment, processing, and other revenue associated with the products noted. |
NOTE 17 – SUBSEQUENT EVENTS
On May 5, 2009, APL redeemed the remaining 5,000 of the 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 Note 6). 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 7, 2009, APL entered into an agreement with Spectra Energy Partners OLP, LP (NYSE: SEP) (“Spectra”) related to the sale of its NOARK gas gathering and interstate pipeline system, including Ozark Gas Transmission, LLC and Ozark Gas Gathering, LLC, for $300.0 million cash. The purchase price will be subject to an adjustment based on the working capital of the NOARK system during the periods between the signing date and closing dates. APL will account for the sale of the NOARK system assets as discontinued operations within the Partnership’s consolidated financial statements in the future. The transaction closed on May 4, 2009 and APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and credit facility (see Note 12).
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 amended preferred units certificate of designation (see Note 6). 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 April 13, 2009, Sunlight exercised its right to convert 5,000 APL Class A Preferred Units into 1,465,653 APL common limited partner units, which was based on 95% of the market value of APL’s closing common unit price for the 10 business days prior to and including March 31, 2009.
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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 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 March 31, 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 12.5% 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 March 31, 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 quarter ended March 31, 2009.
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, Arkoma 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 also provides interstate gas transmission services in southeastern Oklahoma, Arkansas, southern Kansas and southeastern Missouri. 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 March 31, 2009, through its Mid-Continent operations, APL owns and operates:
• | a FERC-regulated, 565-mile interstate pipeline system (“Ozark Gas Transmission”) that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 500 MMcfd; |
• | 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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• | 9,100 miles of active natural gas gathering systems located in Oklahoma, Arkansas, 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 Ozark Gas Transmission, as well as third party pipelines. |
As of March 31, 2009, through its Appalachian operations, APL owns and operates 1,835 miles of natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. Through an omnibus agreement and other agreements between APL and Atlas America, Inc. (“Atlas America” – NASDAQ: ATLS) and its affiliates, a publicly traded company and holder of a 64.4% ownership interest in us and a direct 2.3% ownership interest in APL, including Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin and a publicly-traded company (NYSE: ATN), APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by Atlas Energy. Among other things, the omnibus agreement requires Atlas Energy to connect to APL’s gathering systems wells it operates that are located within 2,500 feet of APL’s gathering systems. APL is also party to natural gas gathering agreements with Atlas America and Atlas Energy under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports.
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 March 31, 2009, APL entered into an agreement with subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) to form a joint venture, Laurel Mountain Midstream, LLC (“Laurel Mountain”), that will own and operate APL’s Appalachia Basin natural gas gathering system, excluding APL’s northern Tennessee operations. To the joint venture, Williams will contribute cash of $102.0 million, of which APL will receive approximately $90.0 million, and a note receivable of $25.5 million. APL will contribute its Appalachia Basin natural gas gathering system. APL will retain a 49% ownership interest in the joint venture, as well as preferred distribution rights relating to all payments on the note receivable. Williams will retain the remaining 51% ownership interest in the joint venture. In addition, ATN will sell to the joint venture two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $12.0 million. Upon the completion of the sale of the APL Appalachia gathering systems to Laurel Mountain, Laurel Mountain will enter into new gas gathering agreements with Atlas Energy which will supersede the existing natural gas gathering agreements and omnibus agreement between APL and Atlas Energy. Under the proposed gas gathering agreement, Atlas Energy will be obligated to pay Laurel Mountain all of the gathering fees it collects from its 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 proposed 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 will account for its share of earnings associated with its ownership interest in Laurel Mountain under the equity method. The transaction is expected to close during the second quarter of 2009. APL will use the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see “—APL Term Loan and Credit Facility”).
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On March 30, 2009, we, pursuant to our right within the Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 of APL’s 12% Class B Preferred Units of limited partner interest (the “Class B Preferred Units”) for cash consideration of $1,000 per Class B Preferred Unit. APL used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. The Class B Preferred Units will receive distributions of 12.0% per annum, paid quarterly to us on the same date as APL’s distribution payment date for its common units (see “–APL Preferred Units – APL Class B Preferred Units”). Additionally, on March 30, 2009, we and APL agreed to amend the terms of the Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the Class B Preferred Units are not convertible into APL common units. The amended Class B Preferred Units Certificate of Designation also gives APL the right at any time to redeem some or all of the outstanding Class B Preferred Units for cash, or an amount equal to the Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 Class B Preferred Units or b) the number of remaining outstanding Class B Preferred Units.
In January 2009, APL and Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, agreed to amend certain terms of the APL Class A Preferred Units Certificate of Designation, 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 APL common units, and (d) established a new price for APL’s call redemption right of $27.25. In addition, the amendment 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. The amendment of the preferred units certificate of designation also required redemption of 15,000 of the APL Class A Preferred Units for cash in future periods. As such, APL reclassified $15.0 million of the $20.0 million of APL Class A Preferred Units outstanding at March 31, 2009 from non-controlling interest in APL within partners’ capital to preferred unit redemption obligation on our consolidated balance sheet. In April 2009, APL and Sunlight Capital agreed that APL would convert 5,000 of the APL Class A Preferred Units into its common units (see “–Subsequent Events”).
Subsequent Events
On May 5, 2009, APL redeemed the remaining 5,000 of the 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 – APL Class A 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 7, 2009, APL entered into an agreement with Spectra Energy Partners OLP, LP (NYSE: SEP) (“Spectra”) related to the sale of its NOARK gas gathering and interstate pipeline system, including Ozark Gas Transmission, LLC and Ozark Gas Gathering, LLC, for $300.0 million cash. The purchase price will be subject to an adjustment based on the working capital of the NOARK system during the periods between the signing date and closing dates. APL will account for the sale of the NOARK system assets as discontinued operations within our consolidated financial statements in the future. The transaction closed on May 4, 2009 and APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and credit facility (see “—APL Term Loan and Credit Facility”).
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 amended preferred units certificate of designation (see “–APL Preferred Units – APL Class A Preferred Units”). 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 April 13, 2009, Sunlight exercised its right to convert 5,000 APL Class A Preferred Units into 1,465,653 APL common limited partner units, which was based on 95% of the market value of APL’s closing common unit price for the 10 business days prior to and including March 31, 2009.
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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. |
In APL’s Appalachian region, substantially all of the natural gas it transports is for Atlas Energy under percentage-of-proceeds (“POP”) contracts, as described below, in which APL earns a fee equal to a percentage, generally 16%, of the gross sales price for natural gas subject, in most cases, to a minimum of $0.35 to $0.40 per thousand cubic feet, or mcf, depending on the ownership of the well. Since APL’s inception in January 2000, its Appalachian system transportation fee has exceeded this minimum generally. APL’s gathering agreements with Atlas Energy will terminate upon the sale of its Appalachia gathering system to Laurel Mountain (see “–Recent Events”). The balance of the Appalachian system natural gas APL transports is for third-party operators generally under fixed-fee contracts.
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 APL’s FERC-regulated transmission pipeline is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation service is provided. 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.
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.
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Recent Trends and Uncertainties
The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.
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. The number of active oil and gas rigs has increased in recent years, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels 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 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 $0.70 per gallon, $3.98 per mmbtu and $55.22 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 March 31, 2010 by approximately $29.6 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.
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Results of Operations
The following table illustrates selected volumetric information related to APL’s reportable segments for the periods indicated:
Three Months Ended March 31, | ||||
2009 | 2008 | |||
Operating data(1): | ||||
Appalachia: | ||||
Average throughput volumes (mcfd) | 98,529 | 75,632 | ||
Mid-Continent: | ||||
Velma system: | ||||
Gathered gas volume (mcfd) | 65,955 | 62,400 | ||
Processed gas volume (mcfd) | 63,875 | 59,867 | ||
Residue gas volume (mcfd) | 50,173 | 47,138 | ||
NGL volume (bpd) | 7,035 | 6,688 | ||
Condensate volume (bpd) | 345 | 254 | ||
Elk City/Sweetwater system: | ||||
Gathered gas volume (mcfd) | 253,878 | 305,377 | ||
Processed gas volume (mcfd) | 253,918 | 236,403 | ||
Residue gas volume (mcfd) | 232,038 | 213,130 | ||
NGL volume (bpd) | 11,719 | 10,677 | ||
Condensate volume (bpd) | 529 | 363 | ||
Chaney Dell system: | ||||
Gathered gas volume (mcfd) | 303,022 | 251,487 | ||
Processed gas volume (mcfd) | 227,855 | 247,861 | ||
Residue gas volume (mcfd) | 255,976 | 220,194 | ||
NGL volume (bpd) | 15,531 | 12,401 | ||
Condensate volume (bpd) | 927 | 707 | ||
Midkiff/Benedum system: | ||||
Gathered gas volume (mcfd) | 153,978 | 142,542 | ||
Processed gas volume (mcfd) | 146,055 | 136,654 | ||
Residue gas volume (mcfd) | 105,238 | 96,612 | ||
NGL volume (bpd) | 22,650 | 20,349 | ||
Condensate volume (bpd) | 789 | 720 | ||
NOARK system: | ||||
Average Ozark Gas Transmission throughput volume (mcfd) | 482,471 | 390,293 |
(1) | “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day. |
Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008
Revenue.Natural gas and liquids revenue was $158.6 million for the three months ended March 31, 2009, a decrease of $207.5 million from $366.1 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from APL’s Chaney Dell system of $69.8 million, APL’s Midkiff/Benedum system of $55.5 million, APL’s Elk City/Sweetwater system of $43.0 million and APL’s Velma system of $35.6 million due to significantly lower average commodity prices in comparison to the prior year comparable period, partially offset by an overall increase in processing volumes and plant production efficiency. Processed natural gas volume on the Elk City/Sweetwater system averaged 253.9 MMcfd for the three months ended March 31, 2009, an increase of 7.4% from the comparable prior year period. NGL
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production volume for the Elk City/Sweetwater system was 11,719 bpd, an increase of 9.8% from the comparable prior year period, as production efficiency of the processing plants increased. The Midkiff/Benedum system had processed natural gas volume of 146.1 MMcfd for the three months ended March 31, 2009, an increase of 6.9% compared to 136.7 MMcfd for the comparable prior year period. NGL production volume for the Midkiff/Benedum system was 22,650 bpd, an increase of 11.3% from the comparable prior year period, as production efficiency of the processing plants increased. Processed natural gas volume averaged 63.9 MMcfd on the Velma system for the three months ended March 31, 2009, an increase of 6.7% from the comparable prior year period. Processed natural gas volume on the Chaney Dell system was 227.9 MMcfd for the three months ended March 31, 2009, a decrease of 8.1% compared to 247.9 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 25.2% from the comparable prior year period to 15,531 bpd for the three months ended March 31, 2009, representing an increase in production efficiency. 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 10 to the consolidated financial statements in Item 1, “Financial Statements”.
Transportation, compression and other fee revenue increased to $26.5 million for the three months ended March 31, 2009 compared with $24.0 million for the comparable prior year period. This $2.5 million increase was primarily due to a $2.7 million increase from APL’s NOARK system and a $1.0 million increase from APL’s Appalachia system due primarily to higher throughput volume, partially offset by $1.2 million decrease of other fee revenue on our other systems. For APL’s NOARK system, average Ozark Gas Transmission volume was 482.5 MMcfd for the three months ended March 31, 2009, an increase of 23.6% from the prior year comparable period due to an increase in throughput capacity to 500.0 MMcfd during the fourth quarter 2008 and higher customer demand. APL’s Appalachia system’s average throughput volume was 98.5 MMcfd for the three months ended March 31, 2009 as compared with 75.6 MMcfd for the comparable prior year period, an increase of 22.9 MMcfd or 30.3%. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to APL’s gathering system.
Other income (loss) net, including the impact of certain gains and losses recognized on APL’s derivatives, was income of $5.1 million for the three months ended March 31, 2009, which represents a favorable movement of $91.9 million from the comparable prior year period loss of $86.8 million. This favorable movement was due primarily to a $42.7 million favorable movement in APL’s non-cash mark-to-market adjustments on derivatives, a favorable movement of $39.3 million related to APL’s cash settlements on derivatives that were not designated as hedges and a non-cash derivative gain of $12.1 million related to APL’s early termination of a portion of its derivative contracts during 2008, partially offset by a net cash loss of $5.0 million related to APL’s early termination of a portion of these derivative contracts (see Note 10 to the consolidated financial statements in Item 1, “Financial Statements”). The $42.7 million favorable movement in non-cash mark-to-market adjustments on APL’s derivatives was due principally to a decrease in forward crude oil market prices from December 31, 2008 to March 31, 2009 and their favorable mark-to-market impact on certain non-hedge derivative contracts APL has 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 March 31, 2009 were $54.05 per barrel, a decrease of $2.89 per barrel from average forward crude oil market prices at December 31, 2008 of $56.94 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 $138.1 million for the three months ended March 31, 2009 represented a decrease of $138.6 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, partially offset by higher APL processing volumes. Plant operating expenses of $13.8 million for the three months ended March 31, 2009 represented a decrease of $1.1 million from the prior year comparable period due to a $1.4 million decrease associated with APL’s Midkiff/Benedum system resulting from lower operating and
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maintenance costs. Transportation and compression expenses increased $1.0 million to $4.8 million for the three months ended March 31, 2009 due to an increase in APL’s Appalachia system operating and maintenance costs as a result of increased capacity and additional well connections in comparison to the prior year period.
General and administrative expense, including amounts reimbursed to affiliates, increased $4.1 million to $10.5 million for the three months ended March 31, 2009 compared with $6.4 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 2009 for the termination of certain positions within APL’s Mid-Continent segment and a $2.1 million non-cash compensation net gain recognized during the first quarter 2008 principally associated with the vesting of certain APL common unit awards that were based on the financial performance of certain APL assets during 2008. A portion of these common unit awards were issued during the first quarter 2009 with the remainder to be issued by APL during the second quarter 2009. As of December 31, 2008, APL recognized the compensation expense associated with these awards in full as we determined the ultimate amount to be issued as of that date (see Note 14 to the consolidated financial statements in Item 1, “Financial Statements”).
Depreciation and amortization increased to $24.7 million for the three months ended March 31, 2009 compared with $21.8 million for the three months ended March 31, 2008 due primarily to depreciation associated APL’s expansion capital expenditures incurred subsequent to March 31, 2008.
Interest expense increased to $21.7 million for the three months ended March 31, 2009 as compared with $20.8 million for the comparable prior year period. This $0.9 million increase was primarily due to a $4.9 million increase in interest expense related to APL’s additional senior notes issued during June 2008 (see “—APL Senior Notes”), partially offset by a $4.9 million decrease in interest expense associated with APL’s senior secured term loan primarily due to its repayment of $122.8 million of indebtedness during June 2008 (see “—APL Term Loan and Credit Facility”) and lower unhedged interest rates (see Note 10 to the consolidated financial statements in Item 1, “Financial Statements”).
Asset impairment of $4.0 million for the three months ended March 31, 2008 consisted of a write-off of costs related to an APL pipeline expansion project. The write-off of costs incurred consisted of a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.
Loss attributable to non-controlling interests decreased $1.6 million to a net income reduction of $0.5 million for the three months ended March 31, 2009 compared with $2.1 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 $23.7 million to an income addition of $20.6 million for the three months ended March 31, 2009 compared with $44.3 million for the comparable prior year period. This change was primarily due to a decrease in APL’s net loss between periods.
Liquidity and Capital Resources
General
Our primary sources of liquidity are distributions received with respect to our ownership interests in APL and borrowings under our credit facility. 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 distributions received from APL and our capital contributions to APL through the retention of cash and borrowings under our credit facility.
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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 |
• | debt principal payments through additional borrowings as they become due or by the issuance of additional limited partner units or APL asset sales. |
At March 31, 2009, we had $46.0 million outstanding and $4.0 million of remaining committed capacity under our credit facility, subject to covenant limitations (see “–– Our Credit Facility”). At March 31, 2009, APL had $324.0 million of outstanding borrowings under its $380.0 million senior secured credit facility and $5.4 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $50.6 million of remaining committed capacity under its credit facility, subject to covenant limitations (see “—APL Term Loan and Credit Facility”). We and APL were in compliance with our respective credit facility’s covenants at March 31, 2009. At March 31, 2009, we had a working capital deficit of $131.4 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 $51.3 million decrease in the current portion of net derivative assets and a $31.1 million decrease in accounts receivable. We believe that we and APL will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we and APL are subject to business, operational and other risks that could adversely affect our cash flow. We and APL may need to supplement our cash generation with proceeds from financing activities, including borrowings under our and APL’s credit facility and other borrowings, the issuance of additional limited partner units and the sale of APL 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.
Cash Flows – Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008
Net cash provided by operating activities of $48.1 million for the three months ended March 31, 2009 represented an increase of $24.7 million from $23.4 million for the prior year comparable period. The increase was derived principally by a $16.8 million increase in cash flows from working capital changes and a $16.5 decrease in cash distributions paid to our non-controlling interest holders, partially offset by an $8.6 million decrease in net loss excluding non-cash charges. The decrease in net loss excluding non-cash charges was principally due to lower APL average commodity prices when compared with the prior year comparable period, partially offset by its higher processing volumes. Non-cash charges which impacted net income excluding non-cash charges include a $30.9 million decrease in non-cash derivative losses and a $4.0 million decrease from APL’s asset impairment loss, partially offset by a $2.8 million increase in depreciation and amortization expense. The movement in non-cash derivative losses resulted from decreases in commodity prices during the
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three months ended March 31, 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 March 31, 2008.
Net cash used in investing activities was $73.0 million for the three months ended March 31, 2009, a decrease of $10.0 million from $83.0 million for the prior year comparable period. This decrease was principally due to an $11.2 million decrease in APL’s capital expenditures, partially offset by 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 financing activities was $20.1 million for the three months ended March 31, 2009, a decrease of $30.4 million from $50.5 million for the comparable prior year period. This decrease was principally due to a $38.0 million net decrease in APL borrowings under its revolving credit facility, partially offset by a $7.6 million decrease in distributions paid to our common 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, excluding amounts paid for acquisitions, for the periods presented (in thousands):
Three Months Ended March 31, | ||||||
2009 | 2008 | |||||
Maintenance capital expenditures | $ | 695 | $ | 1,619 | ||
Expansion capital expenditures | 72,218 | 82,450 | ||||
Total | $ | 72,913 | $ | 84,069 | ||
Expansion capital expenditures decreased to $72.2 million for the three months ended March 31, 2009 compared with $82.5 million for the prior year first quarter 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 first quarter of 2008, partially offset by APL’s continued expansion of its gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas. The decrease in maintenance capital expenditures for the three months ended March 31, 2009 when compared with the comparable prior year period was due to fluctuations in the timing of APL’s scheduled maintenance activity. As of March 31, 2009, APL is committed to expend approximately $56.7 million on pipeline extensions, compressor station upgrades and processing facility upgrades.
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Our Credit Facility
At March 31, 2009, we, with Atlas Pipeline GP as guarantor, had a $50.0 million revolving credit facility with a syndicate of banks which had $46.0 million outstanding. Our credit facility matures in April 2010 and bears interest, at our option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on our outstanding credit facility borrowings at March 31, 2009 was 3.2%. Borrowings under our credit facility are secured by a first-priority lien on a security interest in all of our assets, including a 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 interests in our subsidiaries. We are in compliance with these covenants as of March 31, 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, termination of a material agreement and occurrence of a material adverse effect. Our credit facility requires us to maintain a combined leverage ratio, defined as the ratio of the sum of (i) our funded debt (as defined in our credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility)) of not more than 5.5 to 1.0. In addition, our credit facility requires us to maintain a funded debt (as defined in our credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in our credit facility) of not less than 3.0 to 1.0. Our credit facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable by APL to us in respect of our general partner interest, limited partner interest and incentive distribution rights in APL with respect to the last fiscal quarter in such period, and (ii) our consolidated net income (as defined in our credit facility and as adjusted as provided in our credit facility). As of March 31, 2009, our combined leverage ratio was 5.1 to 1.0, our senior secured debt to EBITDA was 1.5 to 1.0 and our interest coverage ratio was 16.8 to 1.0.
We may borrow under our credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from us to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to our credit facility and (iii) for letters of credit.
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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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.
Off Balance Sheet Arrangements
As of March 31, 2009, our off balance sheet arrangements are limited to APL’s letters of credit outstanding of $5.4 million and its commitments to expend approximately $56.7 million on capital projects.
Our Common Equity Offering
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 Offerings
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.
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APL Cumulative Preferred Units
APL Class A Preferred Units
At March 31, 2009, APL had 20,000 $1,000 par value 12.0% cumulative convertible Class A preferred units of limited partner interests (the “APL Class A Preferred Units”) outstanding that are held by Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates. In January 2009, APL and Sunlight Capital agreed to amend certain terms of the preferred units certificate of designation, 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.
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 APL 10,000 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 APL 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 are required to be redeemed in cash, while APL has the option of redeeming the remaining 5,000 APL Class A Preferred Units in cash or converting the preferred units into APL common limited partner units.
APL follows the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (“SFAS No. 150”). SFAS No. 150 states that financial instruments which are mandatorily redeemable shall be classified as a liability unless the redemption is required to occur only upon the liquidation or termination of the reporting entity. A financial instrument issued in the form of units is mandatorily redeemable if it embodies an unconditional obligation requiring the issuer to redeem the instrument by transferring assets at a specified or determinable date. The amendment of the preferred units certificate of designation required redemption of 15,000 of the APL Class A Preferred Units for cash in future periods. As such, APL reclassified $15.0 million of the $20.0 million of APL Class A Preferred Units outstanding at March 31, 2009 from non-controlling interest in APL to preferred unit redemption obligation on our consolidated balance sheet. In addition, in April 2009, APL and Sunlight Capital agreed that APL would convert 5,000 of the APL Class A Preferred Units into APL common units.
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
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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. We will receive a preferred dividend on the APL Class B Preferred Units of $0.5 million, which is to be paid on May 15, 2009, the same scheduled date as APL’s quarterly cash distribution to its common unitholders and us (see Note 7 to the consolidated financial statements under Item 1, “Financial Statements”).
APL Term Loan and Credit Facility
At March 31, 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 March 31, 2009 was 2.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at March 31, 2009 was 3.3%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $5.4 million was outstanding at March 31, 2009. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet.
In June 2008, APL entered into an amendment to its revolving credit facility and term loan agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to APL’s early termination of certain derivative contracts (see Note 10 to the consolidated financial statements in Item 1, “Financial Statements”) in calculating its 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 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 its revolving credit facility by $80.0 million to $380.0 million.
Borrowings under the APL 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 by the guaranty of each of its 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 in compliance with these covenants as of March 31, 2009. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt or equity issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days. In connection with entering into the credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank based upon the aggregate principal amount of the term loan outstanding, subject to adjustments as stated in the agreement.
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The events which constitute an event of default for APL’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 APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires us to maintain a ratio of funded debt (as defined in the credit facility) to Consolidated EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.75 to 1.0. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of March 31, 2009, APL’s ratio of funded debt to EBITDA was 4.9 to 1.0 and its interest coverage ratio was 4.0 to 1.0.
APL is 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 Senior Notes
At March 31, 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 $270.5 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 $0.6 million of unamortized premium received as of March 31, 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 “—Preferred Units — APL Class A 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 sheets. 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 March 31, 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
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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 March 31, 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.
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 crude oil 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
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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 crude oil 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 June 2008, the Financial Accounting Standards Board (“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.
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 10 to the consolidated financial statements in Item 1, “Financial Statements”).
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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. 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.
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 March 31, 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.
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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 March 31, 2009, we had a $50.0 million revolving credit facility with $46.0 million outstanding. The weighted average interest rate for these borrowings was 3.2% at March 31, 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 revolving credit facility (see —“Our Credit Facility”), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of our floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement is effective at March 31, 2009 and expires on May 28, 2010.
At March 31, 2009, APL had a $380.0 million senior secured revolving credit facility ($324.0 million outstanding). APL also had $707.2 million outstanding under its senior secured term loan at March 31, 2009. The weighted average interest rate for APL’s revolving credit facility borrowings was 2.8% at March 31, 2009, and the weighted average interest rate for the term loan borrowings was 3.3% at March 31, 2009.
At March 31, 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. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements are effective as of March 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010.
Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our and APL’s cumulative interest expense by $6.0 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 $0.70 per gallon, $3.98 per mmbtu and $55.22 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin for the twelve-month period ending March 31, 2010, excluding the effect of non-controlling interests in APL net income (loss), by approximately $29.6 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
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underlying debt instrument is 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 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 income (loss) 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 income (loss) 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. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss) in our 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 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 three months ended March 31, 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 months ended March 31, 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 for the Three Months Ended March 31, | |||||||
2009 | 2008 | ||||||
Net cash derivative expense included within other income (loss), net | $ | (5,000 | ) | $ | — | ||
Net cash derivative expense included within natural gas and liquids revenue | — | — | |||||
Net non-cash derivative income included within other income (loss), net | 12,103 | — | |||||
Net non-cash derivative expense included within natural gas and liquids | (21,944 | ) | — |
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The following table summarizes our and APL’s derivative activity for the periods indicated (amounts in thousands):
Three Months Ended March 31 | ||||||||
2009 | 2008 | |||||||
Loss from cash and non-cash settlement of qualifying hedge instruments(1) | $ | (20,175 | ) | $ | (17,643 | ) | ||
Loss from change in market value of non-qualifying derivatives(2) | (44,990 | ) | (71,196 | ) | ||||
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2) | 10,813 | (5,660 | ) | |||||
Gain (loss) from cash and non-cash settlement of non-qualifying derivatives(2) | 34,495 | (11,925 | ) | |||||
Loss from cash settlement of interest rate derivatives(3) | (3,055 | ) | — |
(1) | Included within natural gas and liquids revenue on our consolidated statements of operations. |
(2) | Included within other income (loss), net on our consolidated statements of operations. |
(3) | Included within interest expense on our consolidated statements of operations. |
The following table summarizes our and APL’s gross fair values of derivative instruments for the period indicated (amounts in thousands):
March 31, 2009 | |||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||
Balance Sheet | Fair Value | Balance Sheet | Fair Value | ||||||||
Derivatives designated as hedging instruments under SFAS No. 133: | |||||||||||
Interest rate contracts | Current portion of derivative asset | $ | — | Current portion of derivative liability | $ | (10,252 | ) | ||||
Interest rate contracts | Long-term derivative asset | — | Long-term derivative liability | (523 | ) | ||||||
Derivatives not designated as hedging instruments under SFAS No. 133: | |||||||||||
Commodity contracts | Current portion of derivative liability | 3,977 | Current portion of derivative liability | (60,991 | ) | ||||||
Commodity contracts | Long-term derivative liability | 2,380 | Long-term derivative liability | (25,147 | ) | ||||||
$ | 6,357 | $ | (96,913 | ) | |||||||
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The following table summarizes the gross effect of our and APL’s cumulative derivative instruments on our consolidated statements of operations for the period indicated (amounts in thousands):
March 31, 2009 | ||||||||||||
Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Location of Gain | Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | Location of Gain (Loss) | |||||||||
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships: | ||||||||||||
Interest rate contracts | $ | (3,055 | ) | Interest expense | $ | — | N/A | |||||
Derivatives not designated as hedging instruments under SFAS No. 133: | ||||||||||||
Commodity contracts(1) | $ | (15,970 | ) | Natural gas and liquids revenue | $ | (9,527 | ) | Other income (loss), net | ||||
Commodity contracts(2) | — | 39,820 | Other income (loss), net | |||||||||
$ | (19,025 | ) | $ | 30,293 | ||||||||
(1) | Hedges previously designated as cash flow hedges |
(2) | Dedesignated cash flow hedges and non-designated hedges |
As of March 31, 2009, we had the following interest rate derivatives:
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 | $ | (444 | ) | ||||
2010 | (204 | ) | |||||||||
$ | (648 | ) |
(1) | Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace. |
As of March 31, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:
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 | $ | (3,374 | ) | ||||
2010 | (304 | ) | |||||||||
$ | (3,678 | ) | |||||||||
April 2008-April 2010 | $ | 250,000,000 | Pay 3.14%—Receive LIBOR | 2009 | $ | (4,715 | ) | ||||
2010 | (1,734 | ) | |||||||||
$ | (6,449 | ) | |||||||||
Natural Gas Liquids Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset(2) | |||||
(gallons) | (per gallon) | (in thousands) | ||||||
2009 | 13,230,000 | $ | 0.745 | $ | 1,579 | |||
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Crude Oil Sales Options (associated with NGL volume)
Production Period Ended December 31, | Crude Volume | Associated NGL Volume | Average Crude Strike Price | Fair Value Asset/(Liability)(1) | Option Type | ||||||||
(barrels) | (gallons) | (per barrel) | (in thousands) | ||||||||||
2009 | 152,100 | 13,542,984 | $ | 111.53 | $ | (11,171 | ) | Puts sold(4) | |||||
2009 | 152,100 | 13,542,984 | $ | 157.82 | — | Calls purchased(4) | |||||||
2009 | 1,588,500 | 88,643,058 | $ | 84.69 | (2,019 | ) | Calls sold | ||||||
2010 | 3,127,500 | 213,088,050 | $ | 86.20 | (13,035 | ) | Calls sold | ||||||
2010 | 714,000 | 45,415,440 | $ | 132.17 | 638 | Calls purchased(4) | |||||||
2011 | 606,000 | 33,145,560 | $ | 100.70 | (3,071 | ) | Calls sold | ||||||
2011 | 252,000 | 13,547,520 | $ | 133.16 | 665 | Calls purchased(4) | |||||||
2012 | 450,000 | 25,893,000 | $ | 102.71 | (2,822 | ) | Calls sold | ||||||
2012 | 180,000 | 9,676,800 | $ | 134.27 | 657 | Calls purchased(4) | |||||||
$ | (30,158 | ) | |||||||||||
Natural Gas Sales – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset (3) | |||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | ||||||
2009 | 360,000 | $ | 8.000 | $ | 1,337 | |||
Natural Gas Basis Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset (3) | ||||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | |||||||
2009 | 3,690,000 | $ | (0.558 | ) | $ | 673 | |||
2010 | 2,220,000 | $ | (0.575 | ) | 301 | ||||
$ | 974 | ||||||||
Natural Gas Purchases – Fixed Price Swaps
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | |||||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | ||||||||
2009 | 7,740,000 | $ | 8.687 | $ | (34,069 | ) | ||||
2010 | 4,380,000 | $ | 8.635 | (12,806 | ) | |||||
$ | (46,875 | ) | ||||||||
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Natural Gas Basis Purchases
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Liability(3) | |||||||
(mmbtu)(5) | (per mmbtu)(5) | (in thousands) | ||||||||
2009 | 11,070,000 | $ | (0.659 | ) | $ | (2,837 | ) | |||
2010 | 6,600,000 | $ | (0.560 | ) | (1,783 | ) | ||||
$ | (4,620 | ) | ||||||||
Ethane Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Asset(1) | Option Type | ||||||
(gallons) | (per gallon) | (in thousands) | ||||||||
2009 | 630,000 | $ | 0.340 | $ | 12 | Puts purchased | ||||
Isobutane Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Liability(1) | Option Type | |||||||
(gallons) | (per gallon) | (in thousands) | |||||||||
2009 | 126,000 | $ | 0.589 | $ | (10 | ) | Puts purchased | ||||
Normal Butane Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Liability(1) | Option Type | |||||||
(gallons) | (per gallon) | (in thousands) | |||||||||
2009 | 126,000 | $ | 0.577 | $ | (10 | ) | Puts purchased | ||||
Natural Gasoline Put Options
Production Period Ended December 31, | Associated NGL Volume | Average Crude Strike Price | Fair Value Liability(1) | Option Type | |||||||
(gallons) | (per gallon) | (in thousands) | |||||||||
2009 | 126,000 | $ | 0.762 | $ | (10 | ) | Puts purchased | ||||
Crude Oil Sales
Production Period Ended December 31, | Volumes | Average Fixed Price | Fair Value Asset(3) | |||||
(barrels) | (per barrel) | (in thousands) | ||||||
2009 | 24,000 | $ | 62.700 | $ | 206 | |||
Crude Oil Sales Options
Production Period Ended December 31, | Volumes | Average Strike Price | Fair Value Liability(1) | Option Type | |||||||
(barrels) | (per barrel) | (in thousands) | |||||||||
2009 | 229,500 | $ | 84.802 | $ | (314 | ) | Calls sold | ||||
2010 | 234,000 | $ | 88.088 | (912 | ) | Calls sold | |||||
2011 | 72,000 | $ | 93.109 | (502 | ) | Calls sold | |||||
2012 | 48,000 | $ | 90.314 | (478 | ) | Calls sold | |||||
$ | (2,206 | ) | |||||||||
Total net liability | $ | (90,556 | ) | ||||||||
(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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(2) | Fair value based upon APL 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) | Puts sold and calls purchased for 2009 represent costless collars entered into by APL as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased by APL for 2010 through 2012 to offset 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. |
(5) | 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.
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 March 31, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.
There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 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 APL’s, 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
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Tulsa County, Oklahoma). Both matters are currently pending. APL believes that the claims are without merit and intend to pursue its action and defend against NNG’s claims. Additionally, APL believes that the ultimate resolution of these matters will not consequently have a material impact on our financial position and 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) | |
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 | |
10.3 | Second Amended and Restated Certificate of Designation for 12% Cumulative Convertible Preferred Units of Atlas Pipeline Partners, L.P. (6) | |
10.4 | Amended and Restated Certificate of Designation for 12% Cumulative Convertible Class B Preferred Units of Atlas Pipeline Partners, L.P. | |
10.5 | Common Unit Purchase Agreement dated June 17, 2008, by and between Atlas America, Inc. and Atlas Pipeline Holdings, L.P.(5) | |
10.6 | Long-Term Incentive Plan(6) | |
10.7 | Revolving Credit Agreement dated as of July 26, 2006(2) | |
31.1 | Rule 13(a)-14(a)/15(d)-14(a) Certification | |
31.2 | Rule 13(a)-14(a)/14(d)-14(a) Certification | |
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. |
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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: May 11, 2009 | By: | /s/ EUGENE N. DUBAY | ||||||
Eugene N. Dubay | ||||||||
Chief Executive Officer, President, and Director of the General Partner | ||||||||
Date: May 11, 2009 | By: | /s/ MATTHEW A. JONES | ||||||
Matthew A. Jones | ||||||||
Chief Financial Officer and Director of the General Partner | ||||||||
Date: May 11, 2009 | By: | /s/ SEAN P. MCGRATH | ||||||
Sean P. McGrath | ||||||||
Chief Accounting Officer of the General Partner |
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