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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
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 ENERGY, 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 x 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 | ¨ | |||
Non-accelerated filer | x (Do not check if smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The number of outstanding common units of the registrant on August 1, 2011 was 51,255,688.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
PAGE | ||||||
PART I. FINANCIAL INFORMATION | ||||||
Item 1. | Financial Statements (Unaudited) | |||||
Consolidated Combined Balance Sheets as of June 30, 2011 and December 31, 2010 | 3 | |||||
Consolidated Combined Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010 | 4 | |||||
Consolidated Combined Statement of Partners’ Capital for the Six Months Ended June 30, 2011 | 5 | |||||
Consolidated Combined Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010 | 6 | |||||
Notes to Consolidated Combined Financial Statements | 7 | |||||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 39 | ||||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 58 | ||||
Item 4. | Controls and Procedures | 61 | ||||
PART II. OTHER INFORMATION | ||||||
Item 6. | Exhibits | 62 | ||||
66 |
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PART I. FINANCIAL INFORMATION
ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED COMBINED BALANCE SHEETS
(in thousands, except share and per share data)
(Unaudited)
June 30, 2011 | December 31, 2010 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 108,692 | $ | 247 | ||||
Accounts receivable | 138,154 | 120,697 | ||||||
Current portion of derivative asset | 982 | 36,621 | ||||||
Prepaid expenses and other | 33,519 | 23,652 | ||||||
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Total current assets | 281,347 | 181,217 | ||||||
Property, plant and equipment, net | 1,922,208 | 1,849,486 | ||||||
Intangible assets, net | 116,649 | 128,543 | ||||||
Investment in joint venture | 85,687 | 153,358 | ||||||
Goodwill, net | 31,784 | 31,784 | ||||||
Long-term derivative asset | 6,291 | 36,125 | ||||||
Other assets, net | 48,754 | 54,749 | ||||||
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$ | 2,492,720 | $ | 2,435,262 | |||||
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LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 217 | $ | 35,625 | ||||
Accounts payable | 95,420 | 79,673 | ||||||
Liabilities associated with drilling contracts | 36,392 | 65,072 | ||||||
Accrued producer liabilities | 89,006 | 72,996 | ||||||
Current portion of derivative liability | 6,404 | 4,917 | ||||||
Current portion of derivative payable to Drilling Partnerships | 26,791 | 30,797 | ||||||
Accrued interest | 1,017 | 1,921 | ||||||
Accrued well drilling and completion costs | 18,293 | 30,126 | ||||||
Advances from affiliates | — | 14,335 | ||||||
Accrued liabilities | 50,212 | 42,654 | ||||||
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Total current liabilities | 323,752 | 378,116 | ||||||
Long-term debt, less current portion | 358,744 | 565,764 | ||||||
Long-term derivative liability | 976 | 11,901 | ||||||
Long-term derivative payable to Drilling Partnerships | 24,741 | 34,796 | ||||||
Other long-term liabilities | 43,335 | 42,896 | ||||||
Commitments and contingencies | ||||||||
Partners’ Capital: | ||||||||
Common limited partners’ interests | 573,142 | 408,720 | ||||||
Accumulated other comprehensive income | 1,873 | 3,882 | ||||||
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575,015 | 412,602 | |||||||
Non-controlling interests | 1,166,157 | 989,187 | ||||||
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Total partners’ capital | 1,741,172 | 1,401,789 | ||||||
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$ | 2,492,720 | $ | 2,435,262 | |||||
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See accompanying notes to consolidated combined financial statements
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues: | ||||||||||||||||
Gas and oil production | $ | 17,723 | $ | 25,230 | $ | 35,349 | $ | 50,710 | ||||||||
Well construction and completion | 10,954 | 43,295 | 28,679 | 115,937 | ||||||||||||
Gathering and processing | 345,734 | 214,016 | 625,952 | 450,562 | ||||||||||||
Administration and oversight | 1,375 | 1,867 | 2,736 | 3,912 | ||||||||||||
Well services | 4,855 | 4,912 | 10,141 | 10,092 | ||||||||||||
Gain (loss) on mark-to-market derivatives | 6,837 | 5,818 | (14,808 | ) | 10,539 | |||||||||||
Other, net | 21,414 | 3,112 | 25,767 | 6,501 | ||||||||||||
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Total revenues | 408,892 | 298,250 | 713,816 | 648,253 | ||||||||||||
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Costs and expenses: | ||||||||||||||||
Gas and oil production | 4,042 | 6,563 | 7,963 | 10,606 | ||||||||||||
Well construction and completion | 9,284 | 36,682 | 24,305 | 98,243 | ||||||||||||
Gathering and processing | 293,471 | 182,827 | 530,455 | 378,989 | ||||||||||||
Well services | 1,674 | 2,812 | 4,034 | 5,275 | ||||||||||||
General and administrative | 22,239 | 6,772 | 38,429 | 17,313 | ||||||||||||
Depreciation, depletion and amortization | 27,370 | 30,115 | 53,977 | 57,212 | ||||||||||||
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Total costs and expenses | 358,080 | 265,771 | 659,163 | 567,638 | ||||||||||||
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Operating income | 50,812 | 32,479 | 54,653 | 80,615 | ||||||||||||
Gain (loss) on asset sales | (233 | ) | — | 255,714 | (2,947 | ) | ||||||||||
Interest expense | (6,567 | ) | (25,119 | ) | (24,645 | ) | (52,140 | ) | ||||||||
Loss on early extinguishment of debt | (19,574 | ) | — | (19,574 | ) | — | ||||||||||
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Income from continuing operations | 24,438 | 7,360 | 266,148 | 25,528 | ||||||||||||
Income (loss) from discontinued operations | — | 7,976 | (81 | ) | 14,757 | |||||||||||
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Net income | 24,438 | 15,336 | 266,067 | 40,285 | ||||||||||||
Income attributable to non-controlling interests | (7,925 | ) | (688 | ) | (219,303 | ) | (2,495 | ) | ||||||||
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Net income after non-controlling interests | 16,513 | 14,648 | 46,764 | 37,790 | ||||||||||||
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2)) | — | (15,788 | ) | (4,711 | ) | (40,294 | ) | |||||||||
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Net income (loss) attributable to common limited partners | $ | 16,513 | $ | (1,140 | ) | $ | 42,053 | $ | (2,504 | ) | ||||||
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Net income (loss) attributable to common limited partners per unit – basic: | ||||||||||||||||
Income (loss) from continuing operations attributable to common limited partners | $ | 0.31 | $ | (0.08 | ) | $ | 0.91 | $ | (0.16 | ) | ||||||
Income from discontinued operations attributable to common limited partners | — | 0.04 | — | 0.07 | ||||||||||||
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Net income (loss) attributable to common limited partners | $ | 0.31 | $ | (0.04 | ) | $ | 0.91 | $ | (0.09 | ) | ||||||
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Net income (loss) attributable to common limited partners per unit – diluted: | ||||||||||||||||
Income (loss) from continuing operations attributable to common limited partners | $ | 0.30 | $ | (0.08 | ) | $ | 0.89 | $ | (0.16 | ) | ||||||
Income from discontinued operations attributable to common limited partners | — | 0.04 | — | 0.07 | ||||||||||||
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Net income (loss) attributable to common limited partners | $ | 0.30 | $ | (0.04 | ) | $ | 0.89 | $ | (0.09 | ) | ||||||
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Weighted average common limited partner units outstanding: | ||||||||||||||||
Basic | 51,235 | 27,704 | 45,156 | 27,704 | ||||||||||||
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Diluted | 53,023 | 27,704 | 46,172 | 27,704 | ||||||||||||
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Net income (loss) attributable to common limited partners: | ||||||||||||||||
Income (loss) from continuing operations | $ | 16,513 | $ | (2,144 | ) | $ | 42,063 | $ | (4,366 | ) | ||||||
Income (loss) from discontinued operations | — | 1,004 | (10 | ) | 1,862 | |||||||||||
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Net income (loss) attributable to common limited partners | $ | 16,513 | $ | (1,140 | ) | $ | 42,053 | $ | (2,504 | ) | ||||||
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See accompanying notes to consolidated combined financial statements.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED COMBINED STATEMENT OF PARTNERS’ CAPITAL
(in thousands, except unit data)
(Unaudited)
Common Limited Partners’ Capital | Accumulated Other Comprehensive Income (Loss) | Non- Controlling Interests | Total | |||||||||||||||||
Units | $ | |||||||||||||||||||
Balance at January 1, 2011 | 27,835,254 | $ | 408,720 | $ | 3,882 | $ | 989,187 | $ | 1,401,789 | |||||||||||
Issuance of common limited partner units related to the acquisition of the Transferred Business (see Note 3) | 23,379,384 | 372,200 | — | — | 372,200 | |||||||||||||||
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3) | — | (251,287 | ) | — | — | (251,287 | ) | |||||||||||||
APL distributions to non-controlling interests | — | — | — | (38,296 | ) | (38,296 | ) | |||||||||||||
Unissued common units under incentive plans | — | 4,612 | — | 1,518 | 6,130 | |||||||||||||||
Issuance of units under incentive plans | 41,050 | (102 | ) | — | 468 | 366 | ||||||||||||||
Distributions paid to common limited partners | — | (7,583 | ) | — | — | (7,583 | ) | |||||||||||||
Distributions equivalent rights paid on unissued units under incentive plans | — | (182 | ) | — | (346 | ) | (528 | ) | ||||||||||||
APL preferred unit distribution | — | — | — | (629 | ) | (629 | ) | |||||||||||||
APL preferred unit redemption | — | — | — | (8,000 | ) | (8,000 | ) | |||||||||||||
Other comprehensive income (loss) | — | — | (2,009 | ) | 2,952 | 943 | ||||||||||||||
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2)) | — | 4,711 | — | — | 4,711 | |||||||||||||||
Net income | — | 42,053 | — | 219,303 | 261,356 | |||||||||||||||
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Balance at June 30, 2011 | 51,255,688 | $ | 573,142 | $ | 1,873 | $ | 1,166,157 | $ | 1,741,172 | |||||||||||
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See accompanying notes to consolidated combined financial statements.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income | $ | 266,067 | $ | 40,285 | ||||
Income (loss) from discontinued operations | (81 | ) | 14,757 | |||||
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Income from continuing operations | 266,148 | 25,528 | ||||||
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 53,977 | 57,212 | ||||||
Amortization of deferred finance costs | 7,233 | 3,255 | ||||||
Non-cash loss on derivative value, net | 47,725 | 35,597 | ||||||
Non-cash compensation expense | 6,130 | 2,736 | ||||||
(Gain) loss on asset sales and dispositions | (255,714 | ) | 2,947 | |||||
Loss on early extinguishment of debt | 19,574 | — | ||||||
Distributions paid to non-controlling interests | (38,642 | ) | (2,330 | ) | ||||
Equity income in unconsolidated companies | (20,956 | ) | (2,295 | ) | ||||
Distributions received from unconsolidated companies | 16,083 | 6,450 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable and prepaid expenses and other | (33,337 | ) | 43,995 | |||||
Accounts payable and accrued liabilities | (9,877 | ) | (99,609 | ) | ||||
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Net cash provided by continuing operating activities | 58,344 | 73,486 | ||||||
Net cash provided by (used in) discontinued operating activities | (81 | ) | 4,382 | |||||
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Net cash provided by operating activities | 58,263 | 77,868 | ||||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Capital expenditures | (106,351 | ) | (62,091 | ) | ||||
Investments in unconsolidated companies | (97,250 | ) | (11,934 | ) | ||||
Net proceeds from asset sales | 411,520 | 210 | ||||||
Other | (1,903 | ) | 895 | |||||
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Net cash provided by (used in) continuing investing activities | 206,016 | (72,920 | ) | |||||
Net cash used in discontinued investing activities | — | (4,382 | ) | |||||
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Net cash provided by (used in) investing activities | 206,016 | (77,302 | ) | |||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Borrowings under credit facilities | 457,000 | 219,000 | ||||||
Repayments under credit facilities | (384,500 | ) | (268,000 | ) | ||||
Repayments of long-term debt | (314,962 | ) | (7,660 | ) | ||||
Payment of premium on early retirement of debt | (14,352 | ) | — | |||||
Net proceeds from equity offerings | — | 15,319 | ||||||
Issuance of Atlas Pipeline Partners, L.P.’s preferred units | — | 8,000 | ||||||
Redemption of Atlas Pipeline Partners, L.P.’s preferred units | (8,000 | ) | — | |||||
Distributions paid to unit holders | (7,583 | ) | (1,385 | ) | ||||
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3) | 120,913 | — | ||||||
Net investment received from Atlas Energy, Inc. prior to February 17, 2011 (see Note 3) | — | 31,213 | ||||||
Deferred financing costs and other | (4,350 | ) | 2,053 | |||||
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Net cash used in financing activities | (155,834 | ) | (1,460 | ) | ||||
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Net change in cash and cash equivalents | 108,445 | (894 | ) | |||||
Cash and cash equivalents, beginning of period | 247 | 1,103 | ||||||
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Cash and cash equivalents, end of period | $ | 108,692 | $ | 209 | ||||
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See accompanying notes to consolidated combined financial statements
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS
June 30, 2011
(Unaudited)
NOTE 1 – BASIS OF PRESENTATION
Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS). On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, an investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of its general partner (see Note 3).
The Partnership also maintains ownership interests in the following entities:
• | Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At June 30, 2011, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.7% common limited partner interest; and |
• | Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At June 30, 2011, the Partnership had an approximate direct and indirect 18% ownership interest in Lightfoot GP. The Partnership also had direct and indirect ownership interest in Lightfoot LP. |
The accompanying consolidated combined financial statements, which are unaudited except that the balance sheet at December 31, 2010 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 combined 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, 2010 (see Note 2). Certain amounts in the prior year’s consolidated combined financial statements have also been reclassified to conform to the current year presentation, including amounts related to APL’s Elk City system, which have been reclassified to discontinued operations following the sale of that system in September 2010 (see Note 5). The results of operations for the three and six month period ended June 30, 2011 may not necessarily be indicative of the results of operations for the full year ending December 31, 2011.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Combination
The consolidated combined financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at June 30, 2011 except for APL, which is controlled by the Partnership. The non-controlling ownership interests in the net income (loss) of APL are reflected within non-controlling interests on the Partnership’s consolidated combined statements of operations. The non-controlling interests in the assets and liabilities of APL are reflected as a component of partners’ capital on the Partnership’s consolidated combined balance sheets. All material intercompany transactions have been eliminated.
In accordance with prevailing accounting literature, management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see Note 3). In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by
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the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in the Partnership’s consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, the Partnership reflected the impact of the acquisition of the Transferred Business on its consolidated combined financial statements in the following manner:
• | Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital (See Note 3); |
• | Retrospectively adjusted its consolidated combined balance sheet as of December 31, 2010, its consolidated combined statement of partners’ capital for the six months ended June 30, 2011, its consolidated combined statements of operations for the six months ended June 30, 2011 and the three and six months ended June 30, 2010, and its consolidated combined statements of cash flows for the six months ended June 30, 2011 and 2010 and the notes to such consolidated combined financial statements to reflect its results combined with the results of the Transferred Business as of or at the beginning of the respective period; and |
• | Adjusted the presentation of its consolidated combined statements of operations for the six months ended June 30, 2011 and the three and six months ended June 30, 2010 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense as AEI was unable to identify and allocate such amounts to the Transferred Business for the respective period. |
In accordance with established practice in the oil and gas industry, the Partnership’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which the Partnership has an interest (“the Drilling Partnerships”). Such interests typically range from 15% to 35%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.
The Partnership’s consolidated combined 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 consolidated combined statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests within partners’ capital on its consolidated combined 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 was reflected within non-controlling interests on the Partnership’s consolidated combined 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). 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.
Use of Estimates
The preparation of the Partnership’s consolidated combined 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 combined financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated combined financial statements are based on a
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number of significant estimates, including the revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical period financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition (see “Principles of Consolidation and Combination”). Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and six months ended June 30, 2011 and 2010 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).
Inventory
The Partnership and APL value inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs have been determined using the first-in, first-out method (“FIFO”). Under this methodology, the cost of products sold consists of APL’s natural gas liquids line fill and condensate inventories. Such costs are adjusted to reflect increases or decreases in inventory quantities, which are valued based on the changes in the FIFO inventory layers.
Property, Plant and Equipment
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired (see “Principles of Consolidation and Combination”). Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation.
The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to 6 Mcf of natural gas.
The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Partnership’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by the Partnership for its interests, properties purchased and working interests with other outside operators.
Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated combined statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated combined balance sheets. Upon the Partnership’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated combined statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.
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Impairment of Long-Lived Assets
The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Partnership’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include the Partnership’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.
The Partnership’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. These assumptions could result in the Partnership’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.
The Partnership’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in a Drilling Partnership which the Partnership may be unable to recover due to the Drilling Partnership’s legal structure. The Partnership may have to pay additional consideration in the future as a well or Drilling Partnership becomes uneconomic under the terms of the Drilling Partnership’s agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Drilling Partnership by the Partnership is governed under the Drilling Partnership’s agreement and in general, must be at fair market value supported by an appraisal of an independent expert selected by the Partnership. There were no impairments of proved oil and gas properties recorded by the Partnership for the three and six months ended June 30, 2011 and 2010.
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved oil and gas properties recorded by the Partnership for the three and six months ended June 30, 2011 and 2010.
During the three months ended December 31, 2010, the Partnership recognized a $49.7 million asset impairment related to oil and gas properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in Tennessee. This impairment related to the carrying amount of these oil and gas properties being in excess of its estimate of their fair value at December 31, 2010. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
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Capitalized Interest
The Partnership and its subsidiaries capitalize 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 combined borrowed funds by the Partnership in the aggregate was 7.3% and 7.4% for the three months ended June 30, 2011 and 2010, respectively, and 7.1% and 7.4% for the six months ended June 30, 2011 and 2010, respectively. The aggregate amount of interest capitalized by the Partnership was $1.1 million and $0.2 million for the three months ended June 30, 2011 and 2010, respectively, and $1.5 million and $0.3 million for the six months ended June 30, 2011 and 2010, respectively.
Intangible Assets
Customer contracts and relationships.APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, which APL amortizes 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 of all intangible assets on an annual basis to determine if adjustments are required. 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’s management’s estimate of whether the individual relationships will continue in excess or less than the average length.
Partnership management and operating contracts.The Partnership recorded its own intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.
The following table reflects the components of intangible assets being amortized at June 30, 2011 and December 31, 2010 (in thousands):
June 30, | December 31, | Estimated Useful Lives | ||||||||||
2011 | 2010 | In Years | ||||||||||
Gross Carrying Amount: | ||||||||||||
Customer contracts and relationships | $ | 205,313 | $ | 205,313 | 3 – 6 | |||||||
Partnership management and operating contracts | 14,344 | 14,344 | 1 –13 | |||||||||
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$ | 219,657 | $ | 219,657 | |||||||||
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Accumulated Amortization: | ||||||||||||
Customer contracts and relationships | $ | (90,487 | ) | $ | (78,934 | ) | ||||||
Partnership management and operating contracts | (12,521 | ) | (12,180 | ) | ||||||||
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$ | (103,008 | ) | $ | (91,114 | ) | |||||||
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Net Carrying Amount: | ||||||||||||
Customer contracts and relationships | $ | 114,826 | $ | 126,379 | ||||||||
Partnership management and operating contracts | 1,823 | 2,164 | ||||||||||
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$ | 116,649 | $ | 128,543 | |||||||||
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Amortization expense on intangible assets was $6.0 million for both the three months ended June 30, 2011 and 2010 and $11.9 million for both the six months ended June 30, 2011 and 2010. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2011 - $23.8 million; 2012 - $23.3 million; 2013 - $23.3 million; 2014 - $19.7 million; and 2015 - $14.7 million.
Goodwill
At June 30, 2011 and December 31, 2010, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. There were no changes in the carrying amount of goodwill for the three and six months ended June 30, 2011 and 2010.
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The Partnership tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including the Partnership’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Partnership’s management also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. The Partnership will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three and six months ended June 30, 2011 and 2010, no impairment indicators arose and no goodwill impairments were recognized by the Partnership.
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 attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit 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 plans and incentive compensation agreements (see Note 16), 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. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income (loss) utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.
The following is a reconciliation of net income (loss) from continuing operations and net income from discontinued operations allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except per unit data):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Continuing operations: | ||||||||||||||||
Net income | $ | 24,438 | $ | 7,360 | $ | 266,148 | $ | 25,528 | ||||||||
(Income) loss attributable to non-controlling interests | (7,925 | ) | 6,284 | (219,374 | ) | 10,400 | ||||||||||
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2)) | — | (15,788 | ) | (4,711 | ) | (40,294 | ) | |||||||||
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Net income (loss) attributable to common limited partners | 16,513 | (2,144 | ) | 42,063 | (4,366 | ) | ||||||||||
Less: Net income attributable to participating securities – phantom units(1) | (512 | ) | — | (820 | ) | — | ||||||||||
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Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit | $ | 16,001 | $ | (2,144 | ) | $ | 41,243 | $ | (4,366 | ) | ||||||
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Discontinued operations: | ||||||||||||||||
Net income (loss) | $ | — | $ | 7,976 | $ | (81 | ) | $ | 14,757 | |||||||
(Income) loss attributable to non-controlling interests | — | (6,972 | ) | 71 | (12,895 | ) | ||||||||||
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Net income (loss) utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit | $ | — | $ | 1,004 | $ | (10 | ) | $ | 1,862 | |||||||
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(1) | Net income attributable to common limited partners’ ownership interests 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). For the three and six months ended June 30, 2010, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 141,000 and 140,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. |
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income 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 plans (see Note 16).
The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Weighted average common limited partners per unit - basic | 51,235 | 27,704 | 45,156 | 27,704 | ||||||||||||
Add effect of dilutive incentive awards(1) | 1,788 | — | 1,016 | — | ||||||||||||
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Weighted average common limited partners per unit - diluted | 53,023 | 27,704 | 46,172 | 27,704 | ||||||||||||
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(1) | For the three and six months ended June 30, 2010, approximately 175,000 and 178,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Revenue Recognition
Certain energy activities are conducted by the Partnership through and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships must pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 180 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned and includes them in administration and oversight revenues within its consolidated combined statements of operations.
The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest and/or overriding royalty. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.
Atlas Pipeline.APL’s revenue primarily consists of the sale of natural gas and liquids, along with the fees earned from its gathering and processing operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced natural gas liquids
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(“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:
• | Fee-Based Contracts. These contracts provide a set fee for gathering and/or 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. APL is also paid a separate compression fee on many of its systems. The fee is dependent upon the volume of gas flowing through its compressors and the quantity of compression stages utilized to gather the gas. |
• | POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. POP contracts may include a fee component, which is charged to the producer. |
• | Keep-Whole Contracts. These contracts require APL, as the gatherer and processor, to gather or purchase raw natural gas at current market rates. The volume of gas gathered or purchased is based on the measured volume at an agreed upon location (generally at the wellhead). The volume of gas redelivered or sold at the tailgate of APL’s processing facility will be lower than the volume purchased at the wellhead primarily due to NGLs extracted when processed through a plant. APL must make up or “keep the producer whole” for this loss in volume. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the volume of residue gas available for redelivery to the producer may be less than received from the producer; or (ii) 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. In order to mitigate the risk associated with keep-whole contracts, APL imposes a fee to gather gas that is settled under this arrangement. In addition, 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. |
The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at June 30, 2011 and December 31, 2010 of $76.0 million and $78.6 million, respectively, which were included in accounts receivable within the Partnership’s consolidated combined balance sheets.
Comprehensive Income
Comprehensive income includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income” and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. The following table sets forth the calculation of the Partnership’s comprehensive income (in thousands):
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Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income | $ | 24,438 | $ | 15,336 | $ | 266,067 | $ | 40,285 | ||||||||
Income attributable to non-controlling interests | (7,925 | ) | (688 | ) | (219,303 | ) | (2,495 | ) | ||||||||
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2)) | — | (15,788 | ) | (4,711 | ) | (40,294 | ) | |||||||||
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Net income (loss) attributable to common unitholders | 16,513 | (1,140 | ) | 42,053 | (2,504 | ) | ||||||||||
Other comprehensive income (loss): | ||||||||||||||||
Net change in fair value of derivative instruments accounted for as cash flow hedges | 6,407 | 1,121 | 6,849 | 21,106 | ||||||||||||
Reclassification adjustment for realized gains in net income (loss) | 126 | 4,222 | (5,904 | ) | 4,361 | |||||||||||
Net change in non-controlling interest related to items in other comprehensive income (loss) | (1,490 | ) | (9,287 | ) | (2,954 | ) | (18,394 | ) | ||||||||
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Total other comprehensive income (loss) | 5,043 | (3,944 | ) | (2,009 | ) | 7,073 | ||||||||||
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Comprehensive income attributable to common unitholders | $ | 21,556 | $ | (5,084 | ) | $ | 40,044 | $ | 4,569 | |||||||
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Recently Adopted Accounting Standards
In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (“Update 2010-29”). The amendments in Update 2010-29 affect any public entity as defined by Topic 805,Business Combinations,that enters into business combinations that are material on an individual or aggregate basis. Update 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Update 2010-29 also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The Partnership applied the requirements of Update 2010-29 upon its adoption on January 1, 2011, and it did not have a material impact on its financial position, results of operations or related disclosures.
In December 2010, the FASB issued Accounting Standards Update 2010-28, Intangibles - Goodwill and Other (Topic 350):When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (“Update 2010-28”). Update 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist in between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Partnership applied the requirements of Update 2010-28 upon its adoption on January 1, 2011, and it did not have a material impact on its financial position, results of operations or related disclosures.
Recently Issued Accounting Standards
In June 2011, the FASB issued Accounting Standards Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“Update 2011-05”). Update 2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. These changes apply to both annual and interim financial statements. Update 2011-05 will be effective for public entities’ fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership will apply the requirements of Update 2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
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NOTE 3 – ACQUISITION FROM ATLAS ENERGY, INC.
On February 17, 2011, the Partnership acquired the Transferred Business from AEI, the former parent of its general partner, which included the following assets:
• | AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which the Partnership will fund a portion of its natural gas and oil well drilling; |
• | proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee; |
• | certain producing natural gas and oil properties, upon which the Partnership will be developers and producers; |
• | all of the ownership interests in Atlas Energy GP, LLC, our general partner; and |
• | a direct and indirect ownership interest in Lightfoot (see Notes 1 and 7). |
For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, the Partnership also received $124.7 million with respect to a contractual cash transaction adjustment from Chevron related to certain liabilities assumed by the Transferred Business. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $528.7 million.
Concurrent with the Partnership’s acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly-owned subsidiary of Chevron. Also concurrent with the Partnership’s acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in the Laurel Mountain joint venture (the “Laurel Mountain Sale”). APL received $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture.
In accordance with prevailing accounting literature, management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see Note 2). As such, the Partnership recognized the assets acquired and liabilities assumed at historical carrying value at the date of acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. The Partnership recognized a non-cash decrease of $251.3 million in partner’s capital on its consolidated combined balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying value of the assets acquired and liabilities assumed, including any the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):
Cash | $ | 159,180 | ||
Accounts receivable | 18,090 | |||
Accounts receivable – affiliate | 45,682 | |||
Prepaid expenses and other | 6,955 | |||
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Total current assets | 229,907 | |||
Property, plant and equipment, net | 516,625 | |||
Goodwill | 31,784 | |||
Intangible assets, net | 2,107 | |||
Other assets, net | 20,416 | |||
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| |||
Total long-term assets | 570,932 | |||
|
| |||
Total assets acquired | $ | 800,839 | ||
|
| |||
Accounts payable | $ | 59,202 |
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Net liabilities associated with drilling contracts | 47,929 | |||
Accrued well completion costs | 39,552 | |||
Current portion of derivative payable to Drilling Partnerships | 25,659 | |||
Accrued liabilities | 25,283 | |||
|
| |||
Total current liabilities | 197,625 | |||
Long-term derivative payable to Drilling Partnerships | 31,719 | |||
Asset retirement obligations | 42,791 | |||
|
| |||
Total long-term liabilities | 74,510 | |||
|
| |||
Total liabilities assumed | $ | 272,135 | ||
|
| |||
Historical carrying value of net assets acquired | $ | 528,704 | ||
|
|
Also in accordance with prevailing accounting literature, the Partnership reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired and retrospectively adjusted its prior year financial statements to furnish comparative information (see Note 2).
NOTE 4 – APL INVESTMENT IN JOINT VENTURE
On May 11, 2011, APL acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“West Texas LPG”) from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. West Texas LPG owns a 2,295 mile common-carrier pipeline system that transports natural gas liquids from New Mexico and Texas to Mont Belvieu, Texas for fractionation. West Texas LPG is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest. APL has accounted for its ownership interest in West Texas LPG under the equity method of accounting, with recognition of its ownership interest in the income of West Texas LPG in other, net on the Partnership’s consolidated combined statements of operations.
NOTE 5 – DISCONTINUED OPERATIONS
On September 16, 2010, APL completed the sale of its Elk City natural gas gathering and processing system to Enbridge Energy Partners, L.P. (NYSE: EEP) for $682.0 million in cash, excluding any working capital or other adjustments. APL used the net proceeds from the transaction to terminate its term loan and reduce borrowings under its revolving credit facility (see Note 9). The Partnership accounted for the sale of the Elk City system assets as discontinued operations within its consolidated combined financial statements and recorded a gain of $312.1 million on the sale within income (loss) from discontinued operations on its consolidated combined statement of operations during the period the transaction occurred.
The following table summarizes the components included within income (loss) from discontinued operations on the Partnership’s consolidated combined statements of operations (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Total revenues | $ | — | $ | 58,032 | $ | — | $ | 100,016 | ||||||||
Total costs and expenses | — | (50,056 | ) | (81 | ) | (85,259 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Income (loss) from discontinued operations | $ | — | $ | 7,976 | $ | (81 | ) | $ | 14,757 | |||||||
|
|
|
|
|
|
|
|
NOTE 6 – PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at the dates indicated (in thousands):
June 30, 2011 | December 31, 2010 | Estimated Useful Lives in Years | ||||||||||
Natural gas and oil properties: | ||||||||||||
Proved properties: | ||||||||||||
Leasehold interests | $ | 48,731 | $ | 46,495 | ||||||||
Pre-development costs | 2,029 | 2,337 | ||||||||||
Wells and related equipment | 807,557 | 798,269 | ||||||||||
|
|
|
| |||||||||
Total proved properties | 858,317 | 847,101 | ||||||||||
Unproved properties | 42,843 | 42,520 | ||||||||||
Support equipment | 8,870 | 8,138 | ||||||||||
|
|
|
| |||||||||
Total natural gas and oil properties | 910,030 | 897,759 | ||||||||||
Pipelines, processing and compression facilities | 1,467,861 | 1,370,230 | 2 – 40 | |||||||||
Rights of way | 157,761 | 156,797 | 20 – 40 | |||||||||
Land, buildings and improvements | 14,800 | 14,465 | 3 – 40 | |||||||||
Other | 29,343 | 26,367 | 3 – 10 | |||||||||
|
|
|
| |||||||||
2,579,795 | 2,465,618 | |||||||||||
Less – accumulated depreciation, depletion and amortization | (657,587 | ) | (616,132 | ) | ||||||||
|
|
|
| |||||||||
$ | 1,922,208 | $ | 1,849,486 | |||||||||
|
|
|
|
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NOTE 7 – OTHER ASSETS
The following is a summary of other assets at the dates indicated (in thousands):
June 30, 2011 | December 31, 2010 | |||||||
Deferred financing costs, net of accumulated amortization of $32,096 and $24,436 at June 30, 2011 and December 31, 2010, respectively | $ | 21,710 | $ | 28,327 | ||||
Investment in Lightfoot | 24,401 | 18,912 | ||||||
Security deposits | 2,643 | 2,841 | ||||||
Long-term derivative receivable from Drilling Partnerships | — | 4,669 | ||||||
|
|
|
| |||||
$ | 48,754 | $ | 54,749 | |||||
|
|
|
|
Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 9). During the three and six months ended June 30, 2011, APL recorded $5.2 million related to accelerated amortization of deferred financing costs associated with the retirement of its 8.125% Senior Notes and partial redemption of its 8.75% Senior Notes (see Note 9). In March 2011, the Partnership recorded $4.9 million of accelerated amortization of deferred financing costs associated with the retirement of its $70.0 million credit facility (see Note 9). In September 2010, APL recorded $4.3 million of accelerated amortization of deferred financing costs associated with the retirement of its term loan with the proceeds from the sale of its Elk City system (see Note 5).
The Partnership owns, directly and indirectly, approximately 13% of Lightfoot LP. In addition, the Partnership owns, directly and indirectly, approximately 18% of Lightfoot GP, the general partner of Lightfoot LP, an entity for which Jonathan Cohen, Chairman of the Partnership’s Board of Directors, is the Chairman of the Board. The Partnership has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the three months ended June 30, 2011, the Partnership recorded a gain associated with its equity ownership interest in Lightfoot of $17.6 million pertaining to its share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP (“IRP”), its metallurgical and steam coal business, in March 2011. This gain was recorded within other, net on the Partnership’s consolidated combined statements of operations. Additionally, the Partnership received a net cash distribution of $13.7 million, representing its share of the cash distribution made to investors by Lightfoot LP with proceeds from the IRP sale.
Long-term derivative receivable from Drilling Partnerships represents a portion of the Partnership’s long-term unrealized derivative liability on contracts that have been allocated to the Drilling Partnerships based on their share of total production volumes sold (see Note 10).
NOTE 8 – ASSET RETIREMENT OBLIGATIONS
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.
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The estimated liability is based on the Partnership’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.
A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Asset retirement obligations, beginning of period | $ | 43,315 | $ | 37,115 | $ | 42,673 | $ | 36,599 | ||||||||
Liabilities incurred | — | 47 | 93 | 47 | ||||||||||||
Liabilities settled | (33 | ) | (67 | ) | (132 | ) | (73 | ) | ||||||||
Accretion expense | 650 | 577 | 1,298 | 1,099 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Asset retirement obligations, end of period | $ | 43,932 | $ | 37,672 | $ | 43,932 | $ | 37,672 | ||||||||
|
|
|
|
|
|
|
|
The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated combined statements of operations and the asset retirement obligation liabilities were included within other long-term liabilities in the Partnership’s consolidated combined balance sheets.
NOTE 9 – DEBT
Total debt consists of the following at the dates indicated (in thousands):
June 30, 2011 | December 31, 2010 | |||||||
Note payable to affiliate | $ | — | $ | 35,415 | ||||
APL revolving credit facility | 142,500 | 70,000 | ||||||
APL 8.125 % senior notes – due 2015 | — | 272,181 | ||||||
APL 8.75 % senior notes – due 2018 | 215,822 | 223,050 | ||||||
APL capital leases | 639 | 743 | ||||||
|
|
|
| |||||
Total debt | 358,961 | 601,389 | ||||||
Less current maturities | (217 | ) | (35,625 | ) | ||||
|
|
|
| |||||
Total long-term debt | $ | 358,744 | $ | 565,764 | ||||
|
|
|
|
Credit Facility
On March 22, 2011, the Partnership entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and a current borrowing base of $160 million. The borrowing base is redetermined semiannually in May and November subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by the Partnership. The Partnership’s borrowing base was increased by its lending group to $160.0 million from $125.0 million upon its regularly scheduled May 2011 redetermination. Up to $20.0 million of the credit facility may be in the form of standby letters of credit, of which $0.8 million was outstanding at June 30, 2011, which was not reflected as borrowings on the Partnership’s consolidated combined balance sheets. The facility is secured by substantially all of the Partnership’s assets and is guaranteed by substantially all of its subsidiaries (excluding APL and its subsidiaries). At June 30, 2011, there were no borrowings outstanding under the credit facility. Borrowings under the credit facility bear interest, at the Partnership’s election, of either LIBOR plus an applicable margin (based upon the utilization of the facility, as defined in the credit agreement) or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin (based on the utilization of the facility, as defined in the credit agreement). The Partnership is also required to pay a fee of 0.5% per annum on the unused
19
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portion of the borrowing base, which is included within interest expense on the Partnership’s consolidated statements of operations.
On February 17, 2011, the Partnership entered into a bridge credit facility with a bank in connection with the closing of the acquisition of the Transferred Business, which was replaced with the credit facility previously noted. The credit facility provided for an initial borrowing base of $70 million and a maturity of February 2012.
The credit agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets. The Partnership was in compliance with these covenants as of June 30, 2011. The credit agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011. Based on the definitions contained in the Partnership’s credit facility, its ratio of current assets to current liabilities was 2.5 to 1.0, its ratio of Total Funded Debt to EBITDA was 0.01 to 1.0 and its ratio of EBITDA to Total Interest Expense was 64.5 to 1.0 at June 30, 2011.
APL Credit Facility
At June 30, 2011, APL had a $350.0 million senior secured revolving credit facility with a syndicate of banks, which matures in December 2015, of which $142.5 million was outstanding (see Note 18). Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at June 30, 2011 was 3.2%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $1.7 million was outstanding at June 30, 2011. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at June 30, 2011. At June 30, 2011, APL had $205.8 million of remaining committed capacity under its credit facility, subject to covenant limitations.
Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures, and by the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.
The events which constitute an event of default for the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s General Partner. APL was in compliance with these covenants as of June 30, 2011.
APL Senior Notes
At June 30, 2011, APL had $215.8 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”). Interest on the APL 8.75% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. The APL 8.75% Senior Notes are subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.
20
Table of Contents
On April 8, 2011, APL redeemed all of its 8.125% senior notes for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. On April 7, 2011, APL redeemed $7.2 million of its APL 8.75% Senior Notes, which were tendered upon its offer to purchase the senior notes at par. APL funded its purchase with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain (see Note 3).
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 was in compliance with these covenants as of June 30, 2011.
Cash payments for interest related to debt made by the Partnership and its subsidiaries were $23.7 million and $55.9 million for the six months ended June 30, 2011 and 2010, respectively.
NOTE 10 – DERIVATIVE INSTRUMENTS
The Partnership and APL use a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity and interest rate price risk management activities. The Partnership and APL enter into financial instruments to hedge forecasted natural gas, NGL, crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs, crude oil and condensate is sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership and APL receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.
The Partnership and APL formally document all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Partnership and APL 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 immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations. For derivatives qualifying as hedges, the Partnership and APL recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income and reclassify the portion relating to the Partnership’s commodity derivatives to gas and oil production revenues and gathering and processing revenues for APL’s commodity derivatives and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated combined statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership and APL recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated combined statements of operations as they occur.
Derivatives are recorded on the Partnership’s consolidated combined balance sheets as assets or liabilities at fair value. The Partnership reflected a net derivative liability on its consolidated combined balance sheets of $0.1 million at June 30, 2011 and a net derivative asset of $55.9 million at December 31, 2010. Of the $1.9 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated combined balance sheet related to derivatives at June 30, 2011, if the fair values of the instruments remain at current market values, the Partnership will reclassify $0.3 million of gains to its consolidated combined statements of operations over the next twelve month period as these contracts expire, consisting of $1.0 million of gains to gas and oil production revenues and $0.7 million of losses to gathering and processing revenues. Aggregate gains of $1.6 million will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as these remaining contracts expire, consisting of $1.9 million of gains to gas and oil production revenues and $0.3 million of losses to gathering and processing revenues. Actual amounts that will be reclassified will vary as a result of future price changes.
21
Table of Contents
The following table summarizes the fair value of the Partnership’s own derivative instruments as of June 30, 2011 and December 31, 2010, as well as the gain or loss recognized in the consolidated combined statements of operations for effective derivative instruments for the three and six months ended June 30, 2011 and 2010:
Contract Type | Balance Sheet Location | June 30, 2011 | December 31, 2010 | |||||||
Commodity contracts | Current portion of derivative asset | $ | 982 | $ | 36,621 | |||||
Commodity contracts | Long-term derivative asset | 1,873 | 36,125 | |||||||
|
|
|
| |||||||
2,855 | 72,746 | |||||||||
|
|
|
| |||||||
Commodity contracts | Current portion of derivative liability | — | (353 | ) | ||||||
Commodity contracts | Long-term derivative liability | — | (6,293 | ) | ||||||
|
|
|
| |||||||
— | (6,646 | ) | ||||||||
|
|
|
| |||||||
Total derivatives | $ | 2,855 | $ | 66,100 | ||||||
|
|
|
|
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Gain (Loss) Recognized in Accumulated OCI | $ | 6,406 | $ | 1,121 | $ | 6,849 | $ | 21,106 | ||||||||
Gain (Loss) Reclassified from Accumulated OCI into Income | $ | (1,577 | ) | $ | (6,435 | ) | $ | (9,308 | ) | $ | (17,072 | ) |
The Partnership enters into natural gas and crude oil future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.
The Partnership recognized gains of $1.6 million and $6.4 million for the three months ended June 30, 2011 and 2010, respectively, and $9.3 million and $17.1 million for the six months ended June 30, 2011 and 2010, respectively, on settled contracts covering natural gas and oil production for historical periods prior to the acquisition of the Transferred Business. These gains are included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and six months ended June 30, 2011 and 2010 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
Prior to its merger transaction with Chevron on February 17, 2011, AEI monetized all of its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business (see Note 3). AEI also monetized derivative instruments which were specifically related to the future natural gas and oil production of the limited partners of the Drilling Partnerships that the Partnership sponsors. Monetization proceeds of $57.4 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents acquired of the Transferred Business at the date of acquisition. The Partnership will allocate the monetization net proceeds received to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. At June 30, 2011, the Partnership recognized a current and long-term derivative payable to Drilling Partnerships of $26.8 million and $24.7 million, respectively, on its consolidated combined balance sheets.
At June 30, 2011, the Partnership had the following commodity derivatives:
Natural Gas Fixed Price Swaps
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Production Period Ending December 31, | Volumes | Average Fixed Price | Fair Value Asset | |||||||||
(mmbtu)(1) | (per mmbtu) (1) | (in thousands) (2) | ||||||||||
2011 | 3,120,000 | $ | 4.484 | $ | 28 | |||||||
2012 | 5,520,000 | $ | 5.000 | 906 | ||||||||
2013 | 3,120,000 | $ | 5.288 | 404 | ||||||||
2014 | 2,880,000 | $ | 5.590 | 484 | ||||||||
2015 | 2,880,000 | $ | 5.861 | 443 | ||||||||
|
| |||||||||||
$ | 2,265 | |||||||||||
|
|
Natural Gas Costless Collars
Production Period Ending December 31, | Option Type | Volumes | Average Floor and Cap | Fair Value Asset/(Liability) | ||||||||||
(mmbtu)(1) | (per mmbtu) (1) | (in thousands)(2) | ||||||||||||
2011 | Puts purchased | 1,620,000 | $ | 3.933 | $ | 128 | ||||||||
2011 | Calls sold | 1,620,000 | $ | 5.584 | (65 | ) | ||||||||
2012 | Puts purchased | 1,920,000 | $ | 4.250 | 484 | |||||||||
2012 | Calls sold | 1,920,000 | $ | 6.084 | (330 | ) | ||||||||
2013 | Puts purchased | 3,120,000 | $ | 4.750 | 1,849 | |||||||||
2013 | Calls sold | 3,120,000 | $ | 6.065 | (1,575 | ) | ||||||||
|
| |||||||||||||
$ | 491 | |||||||||||||
|
|
Crude Oil Costless Collars
Production | Option Type | Volumes | Average Floor and Cap | Fair Value Asset/(Liability) | ||||||||||
(Bbl) (1) | (per Bbl) (1) | (in thousands) (3) | ||||||||||||
2011 | Puts purchased | 30,000 | $ | 90.000 | $ | 78 | ||||||||
2011 | Calls sold | 30,000 | $ | 125.312 | (11 | ) | ||||||||
2012 | Puts purchased | 60,000 | $ | 90.000 | 401 | |||||||||
2012 | Calls sold | 60,000 | $ | 117.912 | (293 | ) | ||||||||
2013 | Puts purchased | 60,000 | $ | 90.000 | 610 | |||||||||
2013 | Calls sold | 60,000 | $ | 116.396 | (561 | ) | ||||||||
2014 | Puts purchased | 24,000 | $ | 80.000 | 204 | |||||||||
2014 | Calls sold | 24,000 | $ | 121.250 | (260 | ) | ||||||||
2015 | Puts purchased | 24,000 | $ | 80.000 | 245 | |||||||||
2015 | Calls sold | 24,000 | $ | 120.750 | (314 | ) | ||||||||
|
| |||||||||||||
$ | 99 | |||||||||||||
|
| |||||||||||||
Total Partnership net liability | $ | 2,855 | ||||||||||||
|
|
(1) | “Mmbtu” represents million British Thermal Units; “Bbl” represents barrels. |
(2) | Fair value based on forward NYMEX natural gas prices, as applicable. |
(3) | Fair value based on forward WTI crude oil prices, as applicable. |
The Partnership’s commodity price risk management activities include the estimated future natural gas and crude oil production of the Drilling Partnerships. Therefore, prior to the Partnership’s acquisition of the Transferred Business, a portion of any unrealized derivative gain or loss was allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas and oil production related to the derivatives not yet settled. Prior to the Partnership’s acquisition of the Transferred Business, AEI monetized all of its derivative instruments, including those related to the future natural gas and oil production of the limited partners of the Drilling Partnerships. At June 30, 2011, hedge monetization cash proceeds of $51.5 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents, and the Partnership will allocate the monetization net proceeds received to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The derivative payable related to the hedge monetization proceeds at June 30, 2011 and net unrealized derivative assets at December 31, 2010 were payable to the limited partners in the Drilling Partnerships and are included in the consolidated combined balance sheets as follows (in thousands):
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Table of Contents
June 30, 2011 | December 31, 2010 | |||||||
Current portion of derivative receivable from Partnerships | $ | — | $ | 138 | ||||
Long-term derivative receivable from Partnerships | $ | — | 4,669 | |||||
Current portion of derivative payable to Partnerships | (26,791 | ) | (30,797 | ) | ||||
Long-term portion of derivative payable to Partnerships | (24,741 | ) | (34,796 | ) | ||||
|
|
|
| |||||
$ | (51,532 | ) | $ | (60,786 | ) | |||
|
|
|
|
Atlas Pipeline Partners
The following table summarizes APL’s gross fair values of derivative instruments for the period indicated (in thousands):
Contract Type | Balance Sheet Location | June 30, 2011 | December 31, 2010 | |||||||
Asset Derivatives | ||||||||||
Commodity contracts | Long-term derivative asset | $ | 4,439 | $ | — | |||||
Commodity contracts | Current portion of derivative liability | 6,169 | 2,624 | |||||||
Commodity contracts | Long-term derivative liability | 4,429 | 1,052 | |||||||
|
|
|
| |||||||
15,037 | 3,676 | |||||||||
|
|
|
| |||||||
Liability Derivatives | ||||||||||
Commodity contracts | Long-term derivative asset | (21 | ) | — | ||||||
Commodity contracts | Current portion of derivative liability | (12,573 | ) | (7,188 | ) | |||||
Commodity contracts | Long-term derivative liability | (5,405 | ) | (6,660 | ) | |||||
|
|
|
| |||||||
(17,999 | ) | (13,848 | ) | |||||||
|
|
|
| |||||||
Total derivatives | $ | (2,962 | ) | $ | (10,172 | ) | ||||
|
|
|
|
As of June 30, 2011, APL had the following commodity derivatives, which do not qualify for hedge accounting:
Fixed Price Swaps
Production Period | Purchased/Sold | Commodity | Volumes(2) | Average Fixed Price | Fair Value(1) Asset/(Liability) (in thousands) | |||||||||||
Natural Gas | ||||||||||||||||
2011 | Sold | Natural Gas Basis | 960,000 | (0.728 | ) | $ | (516 | ) | ||||||||
2011 | Purchased | Natural Gas Basis | 960,000 | (0.758 | ) | 545 | ||||||||||
2011 | Sold | Natural Gas Basis | 2,400,000 | 4.723 | 595 | |||||||||||
Natural Gas Liquids | ||||||||||||||||
2011 | Sold | Propane | 8,568,000 | 1.176 | (2,840 | ) | ||||||||||
2011 | Sold | Isobutane | 1,008,000 | 1.618 | (213 | ) | ||||||||||
2011 | Sold | Normal Butane | 2,772,000 | 1.580 | (766 | ) | ||||||||||
2011 | Sold | Natural Gasoline | 6,552,000 | 2.042 | (1,739 | ) | ||||||||||
2012 | Sold | Propane | 19,278,000 | 1.302 | (1,312 | ) | ||||||||||
2012 | Sold | Normal Butane | 2,520,000 | 1.906 | 310 | |||||||||||
2012 | Sold | Natural Gasoline | 4,158,000 | 2.401 | 579 | |||||||||||
Crude Oil | ||||||||||||||||
2011 | Sold | Crude Oil | 60,000 | 90.680 | (347 | ) | ||||||||||
2012 | Sold | Crude Oil | 180,000 | 103.770 | 683 | |||||||||||
|
| |||||||||||||||
Total Fixed Price Swaps | $ | (5,021 | ) | |||||||||||||
|
|
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Options
Production Period | Purchased/Sold | Type | Commodity | Volumes(2) | Average Strike Price | Fair Value(1) Asset/(Liability) (in thousands) | ||||||||||||
Natural Gas | ||||||||||||||||||
2011 | Purchased | Put | Propane | 10,206,000 | $ | 1.309 | $ | 327 | ||||||||||
2012 | Purchased | Put | Propane | 20,160,000 | $ | 1.399 | 3,329 | |||||||||||
Crude Oil | ||||||||||||||||||
2011 | Purchased | Put | Crude Oil | 192,000 | 98.121 | 1,204 | ||||||||||||
2011 | Sold | Call | Crude Oil | 339,000 | 93.354 | (2,655 | ) | |||||||||||
2011 | Purchased(3) | Call | Crude Oil | 126,000 | 125.200 | 45 | ||||||||||||
2012 | Purchased | Put | Crude Oil | 156,000 | 107.124 | 2,380 | ||||||||||||
2012 | Sold | Call | Crude Oil | 498,000 | 94.694 | (7,116 | ) | |||||||||||
2012 | Purchased(3) | Call | Crude Oil | 180,000 | 125.200 | 623 | ||||||||||||
2013 | Purchased(3) | Put | Crude Oil | 282,000 | 100.100 | 3,922 | ||||||||||||
Total Options | $ | 2,059 | ||||||||||||||||
|
| |||||||||||||||||
Total APL net liability | $ | (2,962 | ) | |||||||||||||||
|
|
(1) | See Note 11 for discussion on fair value methodology. |
(2) | Volumes for natural gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels. |
(3) | Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise. |
The following tables summarize the gross effect of APL’s derivative instruments on the Partnership’s consolidated combined statement of operations for the period indicated (in thousands):
Gain (Loss) Reclassified from Accumulated OCI into Income
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
Contract Type | Location | 2011 | 2010 | 2011 | 2010 | |||||||||||||
Interest rate contracts(2) | Interest expense | $ | — | $ | (457 | ) | $ | — | $ | (2,242 | ) | |||||||
Interest rate contracts(2) | Other, net | — | — | — | — | |||||||||||||
Commodity contracts(2) | Gathering and processing revenue | (1,702 | ) | (5,805 | ) | (3,404 | ) | (10,748 | ) | |||||||||
Commodity contracts(2) | Discontinued operations | — | (4,453 | ) | — | (8,443 | ) | |||||||||||
|
|
|
|
|
|
|
| |||||||||||
$ | (1,702 | ) | $ | (10,715 | ) | $ | (3,404 | ) | $ | (21,433 | ) | |||||||
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
Contract Type | Location | 2011 | 2011 | 2011 | 2011 | |||||||||||||
Interest rate contracts(2) | Gain (loss) on mark-to market derivatives | $ | — | $ | — | $ | — | $ | — | |||||||||
Interest rate contracts(2) | Other, net | — | — | — | (6 | ) | ||||||||||||
Commodity contracts | Gain (loss) on mark-to market derivatives | 6,837 | 5,649 | (14,808 | ) | 9,941 | ||||||||||||
Commodity contracts | Discontinued operations | — | 2,373 | — | 2,220 | |||||||||||||
|
|
|
|
|
|
|
| |||||||||||
$ | 6,837 | $ | 8,022 | $ | (14,808 | ) | $ | 12,155 | ||||||||||
|
|
|
|
|
|
|
|
(1) | Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its Elk City systems (see Note 5). |
(2) | Hedges previously designated as cash flow hedges. |
The fair value of the derivatives included in the Partnership’s consolidated combined balance sheets was as follows (in thousands):
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June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Current portion of derivative asset | $ | 982 | $ | 36,621 | ||||
Long-term derivative asset | 6,291 | 36,125 | ||||||
Current portion of derivative liability | (6,404 | ) | (4,917 | ) | ||||
Long-term derivative liability | (976 | ) | (11,901 | ) | ||||
|
|
|
| |||||
Total Partnership net asset (liability) | $ | (107 | ) | $ | 55,928 | |||
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|
NOTE 11 — FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1–Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 –Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership uses a fair value methodology to value the assets and liabilities for its and APL’s outstanding derivative contracts (see Note 10). The Partnership’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution, and therefore are defined as Level 3 fair value measurements.
Information for assets and liabilities measured at fair value at June 30, 2011 and December 31, 2010 was as follows (in thousands):
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
June 30, 2011 | ||||||||||||||||
Partnership commodity-based derivatives | $ | — | $ | 2,855 | $ | — | $ | 2,855 | ||||||||
APL commodity-based derivatives | — | (637 | ) | (2,325 | ) | (2,962 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total | $ | — | $ | 2,218 | $ | (2,325 | ) | $ | (107 | ) | ||||||
|
|
|
|
|
|
|
| |||||||||
December 31, 2010 | ||||||||||||||||
Partnership commodity-based derivatives | $ | — | $ | 66,100 | $ | — | $ | 66,100 | ||||||||
APL commodity-based derivatives | — | (8,382 | ) | (1,790 | ) | (10,172 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total | $ | — | $ | 57,718 | $ | (1,790 | ) | $ | 55,928 | |||||||
|
|
|
|
|
|
|
|
APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of June 30, 2011 (in thousands):
NGL Fixed Price Swaps | NGL Put Options | Total | ||||||||||||||||||
Volume(1) | Amount | Volume(1) | Amount | Amount | ||||||||||||||||
Balance – January 1, 2011 | 32,760 | $ | (1,790 | ) | — | $ | — | $ | (1,790 | ) | ||||||||||
New contracts | 30,744 | — | 34,776 | 6,954 | 6,954 | |||||||||||||||
Cash settlements(2)(3) | (18,648 | ) | 4,768 | (4,410 | ) | 525 | 5,293 | |||||||||||||
Net change in unrealized loss(2) | — | (8,959 | ) | — | (3,298 | ) | (12,257 | ) | ||||||||||||
Option premium recognition(3) | — | — | — | (525 | ) | (525 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Balance – June 30, 2011 | 44,856 | $ | (5,981 | ) | 30,366 | $ | 3,656 | $ | (2,325 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
(1) | Volumes are stated in thousand gallons. |
(2) | Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations. |
(3) | Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration. |
26
Table of Contents
Other Financial Instruments
The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments.
The Partnership’s other current assets and liabilities on its consolidated combined balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Partnership’s debt at June 30, 2011 and December 31, 2010, which consists principally of APL’s Senior Notes and borrowings under the Partnership’s and APL’s revolving credit facilities, were $344.0 million and $567.7 million, respectively, compared with the carrying amounts of $359.0 million and $601.4 million, respectively. The APL Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 8). Information for assets that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2011 and 2010 were as follows (in thousands):
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Level 3 | Total | Level 3 | Total | |||||||||||||
Asset retirement obligations | $ | — | $ | — | $ | 47 | $ | 47 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Total | $ | — | $ | — | $ | 47 | $ | 47 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Level 3 | Total | Level 3 | Total | |||||||||||||
Asset retirement obligations | $ | 93 | $ | 93 | $ | 47 | $ | 47 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Total | $ | 93 | $ | 93 | $ | 47 | $ | 47 | ||||||||
|
|
|
|
|
|
|
|
NOTE 12 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
In the ordinary course of its business operations, the Partnership conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, the Partnership is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. The Partnership is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective partnership agreements.
NOTE 13 — COMMITMENTS AND CONTINGENCIES
General Commitments
27
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The Partnership is the managing general partner of the Drilling Partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by the Partnership, as managing general partner. The Partnership is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the management of the Partnership believes that any liability incurred would not be material. The Partnership may be required to subordinate a part of its net partnership revenues from the Drilling Partnerships to the benefit of the investor partners for an amount equal to at least 10% of their subscriptions, determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the three months ended June 30, 2011 and 2010, $1.3 million and $1.9 million, respectively, of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships. For the six months ended June 30, 2011 and 2010, $2.7 million and $5.2 million, respectively, of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.
In May 2011, the Partnership entered into a joint venture agreement with Mountain V Oil and Gas, Inc. (“Mountain V”), a privately-held oil and gas exploration and production company, under which the Partnership’s investment drilling programs will invest approximately $35 million to drill 13 wells into the Marcellus Shale formation in Upshur County, West Virginia over the next twelve-month period.
On February 26, 2010, APL received notice from Williams, its former joint venture partner in Laurel Mountain, alleging that certain title defects exist with respect to the real property contributed by APL to Laurel Mountain. Under the Formation and Exchange Agreement with Williams (“Formation Agreement”): (i) Williams had nine months after closing (the “Claim Date”) to assert any alleged title defects, and (ii) APL had 30 days following the Claim Date to contest the title defects asserted by Williams and 180 days following the Claim Date to cure those title defects, which was extended until March 31, 2011. On March 26, 2010, APL delivered notice, disputing Williams’ alleged title defects as well as the amounts claimed. APL has delivered documentation to Williams which should resolve many of the alleged title defects. Although APL’s cure period has technically expired, APL, without objection from Williams, continues to work to resolve the remaining alleged title defects. In addition, AEI delivered a proposed assignment to Laurel Mountain that should resolve some of the alleged deficiencies. Williams also claims, in a letter dated August 26, 2010, that the alleged title defects violate APL’s representation with respect to sufficiency of the assets contributed to Laurel Mountain. If valid, this would make Williams’ title defect claims subject to a higher deductible. APL believes its representations with respect to title are Williams’ sole and exclusive remedy with respect to title matters.
In August 2010, Williams asserted additional indemnity claims under the Formation Agreement totaling approximately $19.8 million. Williams’ claims are generally based on APL’s alleged failure to construct and maintain the assets contributed to Laurel Mountain in accordance with “standard industry practice” or applicable law. As a preliminary matter, APL believes Williams has overstated its claim by forty-nine percent (49%), because, under the Formation Agreement, these claims are reduced on a pro-rata basis to equal Williams’ percentage ownership interest in Laurel Mountain. APL has received additional information from Williams and an adverse outcome is probable with respect to a portion of Williams’ claim. Under the Formation Agreement, Williams’ indemnity claims are capped, in the aggregate, at $27.5 million. In addition, APL is entitled to indemnification from AEI with respect to some of Williams’ claims. APL has established an accrual with respect to the portion of Williams’ claims that it deems probable, which is less than 51% of the amounts asserted by Williams. In addition, APL is entitled to indemnification from AEI with respect to some of Williams’ claims.
The Partnership is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.
As of June 30, 2011, the Partnership and APL are committed to expend approximately $271.3 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.
Legal Proceedings
The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.
NOTE 14 – ISSUANCES OF APL UNITS
28
Table of Contents
The Partnership recognizes gains on APL’s equity transactions as a credit to equity rather than as income pursuant to prevailing accounting literature. These gains represent the Partnership’s portion of the excess net offering price per unit of each of APL’s units over the book carrying amount per unit.
In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to AEI for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units were entitled to distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The APL Class C Preferred Units were not convertible into common units of APL. APL had the right at any time to redeem some or all (but not less than 2,500) of the outstanding APL Class C Preferred Units for cash at an amount equal to the APL Class C Preferred Face Value being redeemed plus accrued but unpaid dividends. On February 17, 2011, the APL Class C Preferred Units were acquired from AEI by Chevron as part of AEI’s merger with Chevron. On May 27, 2011, APL redeemed all 8,000 APL Class C Preferred Units outstanding for cash at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividend on the 8,000 APL Class C Preferred Units prior to APL’s redemption. At June 30, 2011, APL had no preferred units outstanding.
In January 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed on August 20, 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility (see Note 9), and to fund the early termination of certain derivative agreements.
NOTE 15 – 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, 2010 through June 30, 2011 were as follows (in thousands, except per unit amounts):
Date Cash Distribution Paid or Payable | For Quarter Ended | Cash Distribution per Common Limited Partner Unit | ||||
November 16, 2010 | September 30, 2010 | $ | 0.05 | |||
February 18, 2011 | December 31, 2010 | $ | 0.07 | |||
May 20, 2011 | March 31, 2011 | $ | 0.11 |
On July 27, 2011, the Partnership declared a cash distribution of $0.22 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2011. The $11.3 million distribution will be paid on August 19, 2011 to unitholders of record at the close of business on August 8, 2011.
Atlas Pipeline Partners Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and general partner distributions declared by APL for the period from January 1, 2010 through June 30, 2011 were as follows (in thousands, except per unit amounts):
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 | ||||||||||
November 14, 2010 | September 30, 2010 | $ | 0.35 | $ | 18,660 | $ | 363 | |||||||
February 14, 2011 | December 31, 2010 | $ | 0.37 | $ | 19,735 | $ | 398 | |||||||
May 13, 2011 | March 31, 2010 | $ | 0.40 | $ | 21,400 | $ | 2,730 |
29
Table of Contents
On July 26, 2011, APL declared a cash distribution of $0.47 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2011. The $26.4 million distribution, including $3.7 million to the Partnership, will be paid on August 12, 2011 to unitholders of record at the close of business on August 5, 2011.
NOTE 16 – BENEFIT PLANS
2010 Long-Term Incentive Plan
The Board of Directors of the General Partner approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the Partnership’s Board of Directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,300,000 common limited partner units. At June 30, 2011, the Partnership had 3,962,449 phantom units and unit options outstanding under the 2010 LTIP, with 1,337,551 phantom units and unit options available for grant.
Upon a change in control, as defined in the 2010 LTIP, all unvested awards held by directors may immediately vest in full. In the case of awards held by eligible employees, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), in any case following a change in control, any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option.
2010 Phantom Units.A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant a Participant Distribution Equivalent Rights (“DERs”), which are 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. Through June 30, 2011, phantom units granted under the 2010 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Of the phantom units outstanding under the 2010 LTIP at June 30, 2011, there are no units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at June 30, 2011 include DERs granted to the Participants by the LTIP Committee. There was $0.2 million paid with respect to the 2010 LTIP DERs for the three and six months ended June 30, 2011. There were no amounts paid with respect to the 2010 LTIP DERs for the three and six months ended June 30, 2010.
The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of period | 1,566,000 | $ | 22.23 | — | $ | — | ||||||||||
Granted | 153,949 | 22.84 | — | — | ||||||||||||
Vested (1) | — | — | — | — | ||||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2) | 1,719,949 | $ | 22.28 | — | $ | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 2,526 | $ | — | |||||||||||
|
|
|
|
30
Table of Contents
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of period | — | $ | — | — | $ | — | ||||||||||
Granted | 1,719,949 | 22.28 | — | — | ||||||||||||
Vested (1) | — | — | — | — | ||||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2) | 1,719,949 | $ | 22.28 | — | $ | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 2,702 | $ | — | |||||||||||
|
|
|
|
(1) | No phantom unit awards vested during the three and six months ended June 30, 2011 and 2010. |
(2) | The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2011 was $37.4 million. |
At June 30, 2011, the Partnership had approximately $35.6 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.
2010 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 is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also shall determine how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through June 30, 2011, unit options granted under the 2010 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2010 LTIP. There are no unit options outstanding under the 2010 LTIP at June 30, 2011 that will vest within the following twelve months.
The following table sets forth the 2010 LTIP unit option activity for the periods indicated:
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Weighted | Weighted | |||||||||||||||
Number | Average | Number | Average | |||||||||||||
of Unit | Exercise | of Unit | Exercise | |||||||||||||
Options | Price | Options | Price | |||||||||||||
Outstanding, beginning of period | 2,226,000 | $ | 22.23 | — | $ | — | ||||||||||
Granted | 26,500 | 25.45 | — | — | ||||||||||||
Forfeited | (10,000 | ) | 22.23 | — | — | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(1)(2) | 2,242,500 | $ | 22.27 | — | $ | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Options exercisable, end of period(3) | — | $ | — | — | $ | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 1,505 | $ | — | |||||||||||
|
|
|
|
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Weighted | Weighted | |||||||||||||||
Number | Average | Number | Average | |||||||||||||
of Unit | Exercise | of Unit | Exercise | |||||||||||||
Options | Price | Options | Price | |||||||||||||
Outstanding, beginning of period | — | $ | — | — | $ | — | ||||||||||
Granted | 2,252,500 | 22.27 | — | — | ||||||||||||
Forfeited | (10,000 | ) | 22.23 | — | — | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(1)(2) | 2,242,500 | $ | 22.27 | — | $ | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Options exercisable, end of period(3) | — | $ | — | — | $ | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 1,617 | $ | — | |||||||||||
|
|
|
|
(1) | The weighted average remaining contractual life for outstanding options at June 30, 2011 was 9.7 years. |
(2) | The options outstanding at June 30, 2011 had no aggregate intrinsic value. |
(3) | No options were exercisable at June 30, 2011. No options vested during the three and six months ended June 30, 2011 and 2010. |
31
Table of Contents
At June 30, 2011, the Partnership had approximately $20.7 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 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 June 30, 2011 | Six Months Ended June 30, 2011 | |||||||
Expected dividend yield | 1.5 | % | 1.5 | % | ||||
Expected stock price volatility | 48.0 | % | 48.0 | % | ||||
Risk-free interest rate | 2.5 | % | 2.8 | % | ||||
Expected term (in years) | 6.88 | 6.88 | ||||||
Fair value of stock options granted | $ | 11.01 | $ | 9.94 |
2006 Long-Term Incentive Plan
The Board of Directors of the General Partner approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At June 30, 2011, the Partnership had 954,639 phantom units and unit options outstanding under the Partnership 2006 LTIP, with 927,161 phantom units and unit options available for grant.
2006 Phantom Units.Through June 30, 2011, phantom units granted under the 2006 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. Of the phantom units outstanding under the 2006 LTIP at June 30, 2011, 8,928 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at June 30, 2011 include DERs granted to the Participants by the LTIP Committee. The amount paid with respect to 2006 LTIP’s DERs was $3,000 and $5,000 for the three and six months ended June 30, 2011. This amount was recorded as a reduction of partners’ capital on the Partnership’s consolidated combined balance sheet. There were no amounts paid with respect to 2006 LTIP’s DERs for the three and six months ended June 30, 2010.
The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated:
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of period | 31,025 | $ | 7.85 | 138,375 | $ | 22.14 | ||||||||||
Granted | — | — | 6,000 | 6.22 | ||||||||||||
Vested (1) | — | — | — | — | ||||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2) | 31,025 | $ | 7.85 | 144,375 | $ | 21.48 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 70 | $ | 203 | |||||||||||
|
|
|
|
32
Table of Contents
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of period | 27,294 | $ | 5.98 | 138,875 | $ | 22.18 | ||||||||||
Granted | 13,395 | 15.92 | 6,000 | 6.22 | ||||||||||||
Vested (1) | (9,664 | ) | 13.75 | — | — | |||||||||||
Forfeited | — | — | (500 | ) | 32.28 | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2) | 31,025 | $ | 7.85 | 144,375 | $ | 21.48 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 255 | $ | 399 | |||||||||||
|
|
|
|
(1) | No phantom unit awards vested during the three months ended June 30, 2010 and the six months ended June 30, 2010. The intrinsic value for phantom unit awards vested during the six months ended June 30, 2011, was $0.2 million. |
(2) | The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2011 was $0.7 million. |
At June 30, 2011, the Partnership had approximately $0.4 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards.
2006 Unit Options.The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Through June 30, 2011, unit options granted under the 2006 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. There are no unit options outstanding under the 2006 LTIP at June 30, 2011 that will vest within the following twelve months. For the three and six months ended June 30, 2011, the Partnership received $0.1 million from the exercise of options. For the three and six months ended June 30, 2010, no options were exercised.
The following table sets forth the 2006 LTIP unit option activity for the periods indicated:
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||
Outstanding, beginning of period | 955,000 | $ | 20.54 | 955,000 | $ | 20.54 | ||||||||||
Granted | — | — | — | — | ||||||||||||
Exercised(1) | (31,386 | ) | 3.24 | — | — | |||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2)(3) | 923,614 | $ | 21.12 | 955,000 | $ | 20.54 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Options exercisable, end of period(4) | 923,614 | $ | 21.12 | 213,750 | $ | 22.56 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | — | $ | 155 | |||||||||||
|
|
|
|
33
Table of Contents
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||
Outstanding, beginning of period | 955,000 | $ | 20.54 | 955,000 | $ | 20.54 | ||||||||||
Granted | — | — | — | — | ||||||||||||
Exercised(1) | (31,386 | ) | 3.24 | — | — | |||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2)(3) | 923,614 | $ | 21.12 | 955,000 | $ | 20.54 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Options exercisable, end of period(4) | 923,614 | $ | 21.12 | 213,750 | $ | 22.56 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 28 | $ | 310 | |||||||||||
|
|
|
|
(1) | The intrinsic value of options exercised during the six months ended June 30, 2011 was $0.6 million. |
(2) | The weighted average remaining contractual life for outstanding options at June 30, 2011 was 5.5 years. |
(3) | The aggregate intrinsic value of options outstanding at June 30, 2011 was approximately $1.3 million. |
(4) | The weighted average remaining contractual life for options exercisable at June 30, 2011 was 5.5 years. There were no options exercised during the three and six months ended June 30, 2010. |
At June 30, 2011, the Partnership had no unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. The Partnership uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the six months ended June 30, 2011 and 2010 under the 2006 Plan.
APL Long-Term Incentive Plans
APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan (“APL 2010 LTIP”), (collectively the “APL LTIPs”), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. On June 15, 2010, APL’s unitholders approved the terms of the APL 2010 LTIP, which provides for the grant of options, phantom units, unit awards, unit appreciation rights and DERs. The APL LTIPs are administered by a committee (the “APL LTIP Committee”) appointed by APL’s general partner. Under the 2010 APL LTIP, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,000,000 common units, in addition to the 435,000 common units authorized in previous plans. At June 30, 2011, APL had 436,425 phantom units and unit options outstanding under the APL LTIPs, with 2,370,494 phantom units and unit options available for grant. APL is authorized to repurchase common units to cover employee-related taxes on certain phantom units. APL repurchased and retired 23,345 common units for a cost of $0.8 million during the three and six months ended June 30, 2011, which was recorded as a reduction of non-controlling interest on the Partnership’s consolidated balance sheet.
APL Phantom Units.Through June 30, 2011, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”) under APL’s subsidiary’s plan agreed to exchange their APL Bonus Units for an equivalent number of phantom units, effective as of June 1, 2010. These phantom units will vest over a two year period. The first tranche vested on June 1, 2010. Awards may automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at June 30, 2011, 193,195 units will vest within the following twelve months. On February 17, 2011, APL’s employment agreement with its Chief Executive Officer (“CEO”) was terminated in connection with AEI’s merger with Chevron and 75,250 outstanding phantom units, which represents all outstanding phantom units held by APL’s CEO, automatically vested and were issued.
All phantom units outstanding under the APL LTIPs at June 30, 2011 include DERs granted to the participants by the APL LTIP Committee. The amount paid with respect to APL LTIP DERs was $0.1 and $0.3 million for the three and six months ended June 30, 2011, respectively. This amount was recorded as a reduction of non-controlling interest on the Partnership’s consolidated combined balance sheet. No APL LTIP DERs were paid during the three and six months ended June 30, 2010.
34
Table of Contents
The following table sets forth the APL LTIP phantom unit activity for the periods indicated:
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of period | 414,716 | $ | 11.65 | 49,163 | $ | 38.85 | ||||||||||
Granted | 125,123 | 33.03 | 562,500 | 10.35 | ||||||||||||
Vested (1) | (103,414 | ) | 11.36 | (7,889 | ) | 43.15 | ||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2) | 436,425 | $ | 17.84 | 603,774 | $ | 12.24 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands)(3) | $ | 502 | $ | 1,903 | ||||||||||||
|
|
|
| |||||||||||||
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of period | 490,886 | $ | 11.75 | 52,233 | $ | 39.72 | ||||||||||
Granted | 130,853 | 32.93 | 563,500 | 10.35 | ||||||||||||
Vested (1) | (185,314 | ) | 12.35 | (10,584 | ) | 43.05 | ||||||||||
Forfeited | — | — | (1,375 | ) | 43.99 | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2) | 436,425 | $ | 17.84 | 603,774 | $ | 12.24 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands)(3) |
| $ | 1,676 | $ | 2,025 | |||||||||||
|
|
|
|
(1) | The intrinsic values for phantom unit awards vested during the three months ended June 30, 2011 and 2010 were $3.5 million and $0.1 million, respectively, and during the six months ended June 30, 2011 and 2010 were $5.9 million and $0.1 million, respectively. |
(2) | The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2011 was $14.4 million. |
(3) | Non-cash compensation expense for the six months ended June 30, 2011 includes incremental compensation expense of $0.5 million, related to the accelerated vesting of phantom units held by the certain executives of the Partnership. Non-cash compensation expense for the three and six months ended June 30, 2010 includes $1.8 million related to Bonus Units converted to phantom units. |
At June 30, 2011, APL had approximately $5.8 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards.
APL Unit Options.The exercise price of the unit option is equal to the fair market value of APL’s common unit on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through June 30, 2011, unit options granted under the APL LTIPs generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL LTIPs. On February 17, 2011, the employment agreement with the CEO of APL’s General Partner was terminated in connection with AEI’s merger with Chevron and 50,000 outstanding unit options held by its CEO automatically vested. As of June 30, 2011, all unit options were exercised. There are no unit options outstanding under APL LTIPs at June 30, 2011 that will vest within the following twelve months.
35
Table of Contents
The following table sets forth the APL LTIPs’ unit option activity for the periods indicated:
Three Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||
Outstanding, beginning of period | — | $ | — | 100,000 | $ | 6.24 | ||||||||||
Granted | — | — | — | — | ||||||||||||
Exercised | — | — | — | — | ||||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(1) | — | $ | — | 100,000 | $ | 6.24 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Options exercisable, end of period(1) | — | $ | — | 25,000 | $ | 6.24 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) | $ | — | $ | 1 | ||||||||||||
|
|
|
|
Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||
Outstanding, beginning of period | 75,000 | $ | 6.24 | 100,000 | $ | 6.24 | ||||||||||
Granted | — | — | — | — | ||||||||||||
Exercised(1) | (75,000 | ) | 6.24 | — | — | |||||||||||
Forfeited | — | — | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(2) | — | $ | — | 100,000 | $ | 6.24 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Options exercisable, end of period(2) | — | $ | — | 25,000 | $ | 6.24 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands)(3) | $ | 3 | $ | 2 | ||||||||||||
|
|
|
|
(1) | The intrinsic value for the options exercised during the six months ended June 30, 2011 was $1.8 million. |
(2) | No options are outstanding or exercisable. |
(3) | Incremental compensation expense of $2,000, related to the accelerated vesting of options held by APL’s CEO, was recognized during the six months ended June 30, 2011. |
At June 30, 2011, APL had no unrecognized compensation expense related to unvested unit options outstanding under APL’s LTIPs based upon the fair value of the awards.
APL uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the six months ended June 30, 2011 and 2010 under the APL LTIPS.
NOTE 17 — OPERATING SEGMENT INFORMATION
The Partnership’s operations include four reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated are as follows (in thousands):
36
Table of Contents
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010(1) | 2011 | 2010(1) | |||||||||||||
Gas and oil production | ||||||||||||||||
Revenues | $ | 17,723 | $ | 25,230 | $ | 35,349 | $ | 50,710 | ||||||||
Costs and expenses | (4,042 | ) | (6,563 | ) | (7,963 | ) | (10,606 | ) | ||||||||
Depreciation, depletion and amortization expense | (7,178 | ) | (8,938 | ) | (13,744 | ) | (16,835 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Segment income | $ | 6,503 | $ | 9,729 | $ | 13,642 | $ | 23,269 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Well construction and completion | ||||||||||||||||
Revenues | $ | 10,954 | $ | 43,295 | $ | 28,679 | $ | 115,937 | ||||||||
Costs and expenses | (9,284 | ) | (36,682 | ) | (24,305 | ) | (98,243 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Segment income | $ | 1,670 | $ | 6,613 | $ | 4,374 | $ | 17,694 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Other partnership management(2) | ||||||||||||||||
Revenues | $ | 29,994 | $ | 12,610 | $ | 42,243 | $ | 22,876 | ||||||||
Costs and expenses | (7,437 | ) | (10,610 | ) | (15,531 | ) | (17,328 | ) | ||||||||
Depreciation, depletion and amortization expense | (1,069 | ) | (2,553 | ) | (2,204 | ) | (3,296 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Segment income | $ | 21,488 | $ | (553 | ) | $ | 24,508 | $ | 2,252 | |||||||
|
|
|
|
|
|
|
| |||||||||
Atlas Pipeline | ||||||||||||||||
Revenues(3) | $ | 350,221 | $ | 217,115 | $ | 607,545 | $ | 458,730 | ||||||||
Costs and expenses | (287,708 | ) | (175,029 | ) | (518,958 | ) | (366,936 | ) | ||||||||
Depreciation and amortization expense | (19,123 | ) | (18,624 | ) | (38,029 | ) | (37,081 | ) | ||||||||
|
|
|
|
|
|
|
| |||||||||
Segment income | $ | 43,390 | $ | 23,462 | $ | 50,558 | $ | 54,713 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Reconciliation of segment income to net income from continuing operations | ||||||||||||||||
Segment income: | ||||||||||||||||
Gas and oil production | $ | 6,503 | $ | 9,729 | $ | 13,642 | $ | 23,269 | ||||||||
Well construction and completion | 1,670 | 6,613 | 4,374 | 17,694 | ||||||||||||
Other partnership management | 21,488 | (553 | ) | 24,508 | 2,252 | |||||||||||
Atlas Pipeline | 43,390 | 23,462 | 50,558 | 54,713 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total segment income | 73,051 | 39,251 | 93,082 | 97,928 | ||||||||||||
General and administrative expenses(4) | (22,239 | ) | (6,772 | ) | (38,429 | ) | (17,313 | ) | ||||||||
Gain (loss) on asset sales | (233 | ) | — | 255,714 | (2,947 | ) | ||||||||||
Interest expense(4) | (6,567 | ) | (25,119 | ) | (24,645 | ) | (52,140 | ) | ||||||||
Loss on early extinguishment of debt | (19,574 | ) | — | (19,574 | ) | — | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Net income from continuing operations | $ | 24,438 | $ | 7,360 | $ | 266,148 | $ | 25,528 | ||||||||
|
|
|
|
|
|
|
| |||||||||
Capital expenditures | ||||||||||||||||
Gas and oil production | $ | 3,734 | $ | 12,078 | $ | 8,472 | $ | 33,188 | ||||||||
Well construction and completion | — | — | — | — | ||||||||||||
Other partnership management | 1,279 | 1,037 | 2,431 | 7,232 | ||||||||||||
Atlas Pipeline | 73,636 | 13,048 | 91,969 | 19,835 | ||||||||||||
Corporate and other | 1,637 | 736 | 3,479 | 1,836 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total capital expenditures | $ | 80,286 | $ | 26,899 | $ | 106,351 | $ | 62,091 | ||||||||
|
|
|
|
|
|
|
|
June 30, 2011 | December 31, 2010 | |||||||
Balance sheet | �� | |||||||
Goodwill: | ||||||||
Gas and oil production | $ | 18,145 | $ | 18,145 | ||||
Well construction and completion | 6,389 | 6,389 | ||||||
Other partnership management | 7,250 | 7,250 | ||||||
|
|
|
| |||||
$ | 31,784 | $ | 31,784 | |||||
|
|
|
|
37
Table of Contents
Total assets: | ||||||||
Gas and oil production | $ | 521,212 | $ | 592,452 | ||||
Well construction and completion | 6,957 | 9,627 | ||||||
Other partnership management | 45,030 | 38,592 | ||||||
Atlas Pipeline | 1,776,947 | 1,752,568 | ||||||
Corporate and other | 142,574 | 42,023 | ||||||
|
|
|
| |||||
$ | 2,492,720 | $ | 2,435,262 | |||||
|
|
|
|
(1) | Restated to reflect amounts reclassified to discontinued operations due to the sales of certain APL assets in September 2010 (see Note 5). |
(2) | Includes revenues and expenses from well services, transportation, administration and oversight and other income that do not meet the quantitative threshold for reporting segment information. |
(3) | Includes gains of $6.8 million and $5.8 million on mark-to-market derivatives for the three months ended June 30, 2011 and 2010, respectively, and a (loss)/gain of ($14.8) million and $10.5 million on mark-to-market derivatives for the six months ended June 30, 2011 and 2010, respectively. |
(4) | The Partnership notes that interest expense and general and administrative expenses have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented. |
NOTE 18 — SUBSEQUENT EVENTS
Cash Distributions.On July 27, 2011, the Partnership declared a cash distribution of $0.22 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2011. The $11.3 million distribution will be paid on August 19, 2011 to unitholders of record at the close of business on August 8, 2011.
APL Cash Distributions.On July 26, 2011, APL declared a cash distribution of $0.47 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2011. The $26.4 million distribution, including $3.7 million to the Partnership, will be paid on August 12, 2011 to unitholders of record at the close of business on August 5, 2011.
APL Credit Facility. On July 8, 2011, APL exercised the $100.0 million accordion feature on its revolving credit facility to increase the capacity from $350.0 million to $450.0 million. The other terms of the credit agreement put in place in December 2010 remain unchanged.
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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, “Risk Factors”, in our annual report on Form 10-K for the year ended December 31, 2010. 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.
BUSINESS OVERVIEW
We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS). On February 17, 2011, we acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner (see “Recent Developments”). These assets principally included the following:
• | AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we will fund a portion of our natural gas and oil well drilling; |
• | proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee; |
• | certain producing natural gas and oil properties, upon which the Partnership will be developers and producers; |
• | all of the ownership interests in Atlas Energy GP, LLC, our general partner; and |
• | a direct and indirect ownership interest in Lightfoot LP and Lightfoot GP (collectively, “Lightfoot”), which incubate new MLPs and invest in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP. We also have direct and indirect ownership interests in Lightfoot LP. |
We also maintain an ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At June 30, 2011, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.7% common limited partner interest.
FINANCIAL PRESENTATION
Our consolidated combined financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at June 30, 2011 except for APL, which we control. Due to the structure of our ownership interests in APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in APL are reflected as income attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated combined balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us, our wholly-owned subsidiaries and the consolidated results of APL, adjusted for non-controlling interests in APL’s net income.
In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control (see “Recent Developments”). In comparison to the purchase method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value
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at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital. Also, in comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:
• | Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital; |
• | Retrospectively adjusted our consolidated combined balance sheet as of December 31, 2010, our consolidated combined statement of partners’ capital for the six months ended June 30, 2011, and our consolidated combined statements of operations for the six months ended June 30, 2011 and the three and six months ended June 30, 2010, and our consolidated combined statements of cash flows for the six months ended June 30, 2011 and 2010 to reflect our results combined with the results of the Transferred Business as of or at the beginning of the respective period; and |
• | Adjusted the presentation of our consolidated combined statements of operations for the six months ended June 30, 2011 and the three and six months ended June 30, 2010 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. Furthermore, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense as we were unable to identify and allocate such amounts to the Transferred Business for the respective period. |
APL completed the sale of its Elk City system on September 16, 2010. As such, we have adjusted the prior year consolidated financial information presented to reflect the amounts related to the operations of this system as discontinued operations.
SUBSEQUENT EVENTS
Cash Distributions.On July 27, 2011, we declared a cash distribution of $0.22 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2011. The $11.3 million distribution will be paid on August 19, 2011 to unitholders of record at the close of business on August 8, 2011.
APL Cash Distributions.On July 26, 2011, APL declared a cash distribution of $0.47 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2011. The $26.4 million distribution, including $3.7 million to us, will be paid on August 12, 2011 to unitholders of record at the close of business on August 5, 2011.
APL Credit Facility. On July 8, 2011, APL exercised the $100.0 million accordion feature on its revolving credit facility to increase the capacity from $350.0 million to $450.0 million. The other terms of the credit agreement put in place in December 2010 remain unchanged.
RECENT DEVELOPMENTS
Redemption of APL Preferred Units.In May 2011, APL redeemed its 8,000 APL Class C Preferred Units outstanding for cash at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million of accrued dividends. At June 30, 2011, APL had no preferred units outstanding.
APL Pipeline Acquisition.In May 2011, APL acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“West Texas LPG”) from Buckeye Partners, L.P. for $85.0 million. West Texas LPG owns a 2,295 mile common-carrier pipeline system that transports natural gas liquids from New Mexico and Texas to Mont Belvieu for fractionation. West Texas LPG is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest.
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Redemption of APL Senior Notes.In April 2011, APL completed the redemption of all of its 8.125% Senior Notes for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. Also in April, APL redeemed $7.2 million of the APL 8.75% Senior Notes, which were tendered upon its offer to purchase the senior notes at par. APL funded its purchase with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain.
New Credit Facility. In March 2011, we entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and an initial borrowing base of $125 million. The borrowing base is redetermined semiannually in May and November subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes we issued. Our borrowing base was increased by our lending group to $160.0 million from $125.0 million upon the regularly scheduled May 2011 redetermination. Up to $20.0 million of the credit facility may be in the form of standby letters of credit. The facility is secured by substantially all of our assets and is guaranteed by substantially all of our subsidiaries (excluding APL and its subsidiaries). The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also requires us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011.
In February 2011, we entered into a bridge credit facility with a bank in connection with the closing of the acquisition of the Transferred Business, which was replaced with the current credit facility. The credit facility provided for an initial borrowing base of $70 million and a maturity of February 2012.
Acquisition from AEI.On February 17, 2011, we completed an acquisition of the Transferred Business from AEI, the former parent of our general partner, which included the following assets:
• | AEI’s investment management business, which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which we will fund a portion of our natural gas and oil well drilling; |
• | proved reserves located in the Appalachia Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan, and the Chattanooga Shale of northeastern Tennessee; |
• | certain producing natural gas and oil properties, upon which the Partnership will be developers and producers; |
• | all of the ownership interests in Atlas Energy GP LLC, our general partner; and |
• | a direct and indirect ownership interest in Lightfoot, which incubates new MLPs and invests in existing MLPs. We have an approximate direct and indirect 18% ownership interest in Lightfoot GP. We also have direct and indirect ownership interests in Lightfoot LP. |
For the assets acquired and liabilities assumed, we issued approximately 23.4 million of our common limited partner units and paid $30.0 million in cash consideration. Based on our February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, we also received $124.7 million with respect to a contractual cash transaction adjustment from Chevron related to certain liabilities assumed by the Transferred Business. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $528.7 million.
Concurrent with our acquisition of the Transferred Business, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly-owned subsidiary of Chevron. Also concurrent with our acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in the Laurel Mountain joint venture (the “Laurel Mountain Sale”). APL received $409.5 million in cash, net of expenses, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights
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under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture.
CONTRACTUAL REVENUE ARRANGEMENTS
Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices, and the gas produced in the Niobrara formation has been primarily based upon the Cheyenne Index.
Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.
Investment Partnerships. We generally have funded a portion of our drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. As managing general partner of the investment partnerships, we receive the following fees:
• | Well construction and completion.For each well that is drilled by an investment partnership, we receive an 18% mark-up on those costs incurred to drill and complete the well; |
• | Administration and oversight.For each well drilled by an investment partnership, we receive a fixed fee of approximately $249,000 for horizontal wells drilled and a range of $15,700 to $62,200 for all other well types. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well; and |
• | Well services.Each partnership pays us a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well. |
APL’s principal revenue is generated from the gathering and sale of natural gas, natural gas liquids (“NGL”s) and condensate. Variables that affect its revenue are:
• | the volumes of natural gas APL gathers 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, NGLs and condensate; |
• | the price of the natural gas APL gathers and processes and the NGLs and condensate it recovers and sells, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States; |
• | the NGL and BTU content of the gas that is gathered and processed; |
• | the contract terms with each producer; and |
• | the efficiency of APL’s gathering systems and processing plants. |
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 and NGLs off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas.
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GENERAL TRENDS AND OUTLOOK
We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural Gas Supply and Outlook.The areas in which we operate are experiencing a decline in the development of shallow wells, but a significant increase in drilling activity related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves.
Reserve Outlook. Our future oil and gas reserves, production, cash flow and our ability to make payments on our revolving credit facility depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.
RESULTS OF OPERATIONS
GAS AND OIL PRODUCTION
Production Profile.Currently, we have focused our natural gas and oil production operations in various shale plays in the northeastern and midwestern United States. As part of our agreement with AEI to acquire the Transferred Business, we have entered into certain agreements which restrict our ability to drill additional wells in certain areas of the Marcellus Shale. Through June 30, 2011, we have established production positions in the following areas:
• | Appalachia basin, including activities in the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas; |
• | Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas; |
• | New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; |
• | Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale; and |
• | Chattanooga Shale in northeastern Tennessee, which enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone. |
The following table presents the number of wells we drilled, both gross and for our interest, and the number of gross wells we turned in line during the three and six months ended June 30, 2011 and 2010:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Gross wells drilled: | ||||||||||||||||
Appalachia | — | — | 3 | 10 | ||||||||||||
New Albany/Antrim | — | 27 | — | 27 | ||||||||||||
Niobrara | — | — | 17 | — | ||||||||||||
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— | 27 | 20 | 37 | |||||||||||||
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Our share of gross wells drilled(1): | ||||||||||||||||
Appalachia | — | — | 1 | 2 |
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New Albany/Antrim | — | 7 | — | 7 | ||||||||||||
Niobrara | — | — | 5 | — | ||||||||||||
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— | 7 | 6 | 9 | |||||||||||||
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Gross wells turned in line: | ||||||||||||||||
Appalachia | — | 32 | 1 | 67 | ||||||||||||
New Albany/Antrim | 1 | 16 | 13 | 34 | ||||||||||||
Niobrara | 12 | — | 30 | — | ||||||||||||
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13 | 48 | 44 | 101 | |||||||||||||
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(1) | Includes (i) our percentage interest in the wells in which we have a direct ownership interest and (ii) our percentage interest in the wells based on our percentage interest in our investment partnerships. |
Production Volumes. The following table presents our total net gas and oil production volumes and production per day for the three and six months ended June 30, 2011 and 2010:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Production:(1)(2) | ||||||||||||||||
Appalachia:(3) | ||||||||||||||||
Natural gas (MMcf) | 2,567 | 3,176 | 5,197 | 6,507 | ||||||||||||
Oil (000’s Bbls) | 73 | (4) | 77 | (4) | 139 | (4) | 154 | (4) | ||||||||
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Total (MMcfe) | 3,007 | 3,638 | 6,030 | 7,431 | ||||||||||||
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New Albany/Antrim: | ||||||||||||||||
Natural gas (MMcf) | 291 | 147 | 582 | 239 | ||||||||||||
Oil (000’s Bbls) | — | — | — | — | ||||||||||||
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Total (MMcfe) | 291 | 147 | 582 | 239 | ||||||||||||
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Niobrara: | ||||||||||||||||
Natural gas (MMcf) | 36 | — | 53 | — | ||||||||||||
Oil (000’s Bbls) | — | — | — | — | ||||||||||||
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Total (MMcfe) | 36 | — | 53 | — | ||||||||||||
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Total: | ||||||||||||||||
Natural gas (MMcf) | 2,894 | 3,323 | 5,833 | 6,746 | ||||||||||||
Oil (000’s Bbls) | 73 | (4) | 77 | (4) | 139 | (4) | 154 | (4) | ||||||||
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Total (MMcfe) | 3,334 | 3,785 | 6,665 | 7,670 | ||||||||||||
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Production per day: (1)(2) | ||||||||||||||||
Appalachia:(3) | ||||||||||||||||
Natural gas (Mcfd) | 28,208 | 34,902 | 28,714 | 35,949 | ||||||||||||
Oil (Bpd) | 806 | (4) | 846 | (4) | 767 | (4) | 851 | (4) | ||||||||
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Total (Mcfed) | 33,042 | 39,979 | 33,314 | 41,057 | ||||||||||||
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New Albany/Antrim: | ||||||||||||||||
Natural gas (Mcfd) | 3,192 | 1,615 | 3,218 | 1,320 | ||||||||||||
Oil (Bpd) | — | — | — | — | ||||||||||||
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Total (Mcfed) | 3,192 | 1,615 | 3,218 | 1,320 | ||||||||||||
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Niobrara: | ||||||||||||||||
Natural gas (Mcfd) | 399 | — | 293 | — | ||||||||||||
Oil (Bpd) | — | — | — | — | ||||||||||||
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Total (Mcfed) | 399 | — | 293 | — | ||||||||||||
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Total: | ||||||||||||||||
Natural gas (Mcfd) | 31,799 | 36,517 | 32,225 | 37,269 | ||||||||||||
Oil (bpd) | 806 | (4) | 846 | (4) | 767 | (4) | 851 | (4) | ||||||||
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Total (Mcfed) | 36,633 | 41,594 | 36,825 | 42,377 | ||||||||||||
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(1) | Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells |
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owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells. |
(2) | “MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ration of approximately six Mcf’s to one barrel. |
(3) | Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee. |
(4) | Includes NGL production volume for the three and six months ended June 30, 2011 and 2010. |
Production Revenues, Prices and Costs. Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 94% of our proved reserves on an energy equivalent basis at December 31, 2010. The following table presents our production revenues and average sales prices for our natural gas and oil production for the three and six months ended June 30, 2011 and 2010, along with our average production costs, taxes, and transmission and compression costs in each of the reported periods:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Production revenues (in thousands): | ||||||||||||||||
Appalachia:(1) | ||||||||||||||||
Natural gas revenue | $ | 10,947 | $ | 19,829 | $ | 23,162 | $ | 40,491 | ||||||||
Oil revenue | 5,251 | (5) | 4,560 | (5) | 9,155 | (5) | 8,773 | (5) | ||||||||
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Total revenues | $ | 16,198 | $ | 24,389 | $ | 32,317 | $ | 49,264 | ||||||||
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New Albany/Antrim: | ||||||||||||||||
Natural gas revenue | $ | 1,330 | $ | 841 | $ | 2,769 | $ | 1,446 | ||||||||
Oil revenue | — | — | — | — | ||||||||||||
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Total revenues | $ | 1,330 | $ | 841 | $ | 2,769 | $ | 1,446 | ||||||||
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Niobrara: | ||||||||||||||||
Natural gas revenue | $ | 195 | $ | — | $ | 263 | $ | — | ||||||||
Oil revenue | — | — | — | — | ||||||||||||
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Total revenues | $ | 195 | $ | — | $ | 263 | $ | — | ||||||||
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Total: | ||||||||||||||||
Natural gas revenue | $ | 12,472 | $ | 20,670 | $ | 26,194 | $ | 41,937 | ||||||||
Oil revenue | 5,251 | (5) | 4,560 | (5) | 9,155 | (5) | 8,773 | (5) | ||||||||
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Total revenues | $ | 17,723 | $ | 25,230 | $ | 35,349 | $ | 50,710 | ||||||||
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Average sales price:(2) | ||||||||||||||||
Natural gas (per Mcf): | ||||||||||||||||
Total realized price, after hedge (3) | $ | 5.15 | $ | 7.17 | $ | 5.31 | $ | 7.41 | ||||||||
Total realized price, before hedge (3) | $ | 5.05 | $ | 4.37 | $ | 4.64 | $ | 5.20 | ||||||||
Oil (per Bbl): | ||||||||||||||||
Total realized price, after hedge | $ | 99.70 | $ | 79.64 | $ | 94.32 | $ | 76.10 | ||||||||
Total realized price, before hedge | $ | 99.70 | $ | 72.76 | $ | 92.25 | $ | 70.09 | ||||||||
Production costs (per Mcfe):(2) | ||||||||||||||||
Appalachia:(1) | ||||||||||||||||
Lease operating expenses(4) | $ | 1.03 | $ | 1.38 | $ | 0.94 | $ | 1.11 | ||||||||
Production taxes | 0.03 | 0.03 | 0.05 | 0.03 | ||||||||||||
Transportation and compression | 0.50 | 0.64 | 0.53 | 0.61 | ||||||||||||
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$ | 1.55 | $ | 2.05 | $ | 1.52 | $ | 1.74 | |||||||||
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New Albany/Antrim: | ||||||||||||||||
Lease operating expenses | $ | 1.33 | $ | 1.86 | $ | 1.22 | $ | 1.83 | ||||||||
Production taxes | 0.15 | 0.10 | 0.12 | 0.11 | ||||||||||||
Transportation and compression | 0.12 | 0.10 | 0.10 | 0.09 | ||||||||||||
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$ | 1.61 | $ | 2.06 | $ | 1.44 | $ | 2.03 | |||||||||
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Niobrara: | ||||||||||||||||
Lease operating expenses | $ | 0.61 | $ | — | $ | 0.62 | $ | — | ||||||||
Production taxes | 0.03 | — | 0.02 | — | ||||||||||||
Transportation and compression | 0.22 | — | 0.25 | — | ||||||||||||
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$ | 0.85 | $ | — | $ | 0.89 | $ | — | |||||||||
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Total: | ||||||||||||||||
Lease operating expenses(4) | $ | 1.05 | $ | 1.40 | $ | 0.96 | $ | 1.13 | ||||||||
Production taxes | 0.04 | 0.03 | 0.05 | 0.04 | ||||||||||||
Transportation and compression | 0.46 | 0.62 | 0.49 | 0.59 | ||||||||||||
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$ | 1.55 | $ | 2.05 | $ | 1.51 | $ | 1.75 | |||||||||
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(1) | Appalachia includes our operations located in Pennsylvania, Ohio, New York, West Virginia and Tennessee. |
(2) | “Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels. |
(3) | Excludes the impact of certain allocations of production revenue to investor partners within our investment partnerships for the three and six months ended June 30, 2011 and 2010. Including the effect of these allocations, the average realized gas sales price was $4.31 per Mcf ($4.20 per Mcf before the effects of financial hedging) and $6.22 per Mcf ($3.43 per Mcf before the effects of financial hedging) for the three months ended June 30, 2011 and 2010, respectively, and $4.49 per Mcf ($3.82 per Mcf before the effects of financial hedging) and $6.22 per Mcf ($4.01 per Mcf before the effects of financial hedging) for the six months ended June 30, 2011 and 2010, respectively. |
(4) | Excludes the effects of our proportionate share of lease operating expenses associated with certain allocations of production revenue to investor partners within our investment partnerships for the three and six months ended June 30, 2011 and 2010. Including the effects of these costs, Appalachia lease operating expenses per Mcfe were $0.65 per Mcfe ($1.18 per Mcfe for total production costs) and $1.05 per Mcfe ($1.72 per Mcfe for total production costs) for the three months ended June 30, 2011 and 2010, respectively, and $0.59 per Mcfe ($1.17 per Mcfe for total production costs) and $0.72 per Mcfe ($1.36 per Mcfe for total production costs) for the six months ended June 30, 2011 and 2010, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $0.71 per Mcfe ($1.21 per Mcfe for total production costs) and $1.08 per Mcfe ($1.73 per Mcfe for total production costs) for the three months ended June 30, 2011 and 2010, respectively, and $0.65 per Mcfe ($1.19 per Mcfe for total production costs) and $0.76 per Mcfe ($1.38 per Mcfe for total production costs) for the six months ended June 30, 2011 and 2010, respectively. |
(5) | Includes NGL production revenue for the three and six months ended June 30, 2011 and 2010. |
Three Months Ended June 30, 2011 Compared with the Three Months Ended June 30, 2010.Total natural gas revenues were $12.5 million for the three months ended June 30, 2011, a decrease of $8.2 million from $20.7 million for the three months ended June 30, 2010. This decrease consisted of a $5.8 million decrease attributable to lower realized natural gas prices and a $3.1 million decrease attributable to lower production volumes, partially offset by a $0.7 million decrease in gas revenues allocated to the investor partners within our investment partnerships for the three months ended June 30, 2011 compared with the prior year period. Total oil revenues were $5.2 million for the three months ended June 30, 2011, an increase of $0.7 million from $4.5 million for the comparable prior year period. This increase was attributable to a $0.6 million increase from the sale of natural gas liquids and a $0.6 million increase associated with higher average realized prices, partially offset by a $0.5 million decrease associated with lower oil production volumes in comparison to the prior year period.
Appalachia production costs were $3.5 million for the three months ended June 30, 2011, a decrease of $2.8 million from $6.3 million for the three months ended June 30, 2010. This decrease was due primarily to a $0.8 million decrease in transportation costs, a $0.7 million decrease associated with water hauling and disposal costs, a $0.5 million decrease for labor-related costs and a $0.9 million decrease for maintenance expenses and other costs associated with our gas and oil operations. New Albany/Antrim production costs were $0.5 million for the three months ended June 30, 2011, an increase of $0.2 million from $0.3 million for the comparable prior year period. This increase was primarily attributable to a $0.1 million increase for labor-related costs and a $0.1 million increase associated with parts, materials and other costs associated with our increased natural gas production in New Albany/Antrim.
Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010.Total natural gas revenues were $26.2 million for the six months ended June 30, 2011, a decrease of $15.7 million from $41.9 million for the six months ended June 30, 2010. This decrease consisted of a $12.2 million decrease attributable to lower realized natural gas prices and a $6.8 million decrease attributable to lower production volumes, partially offset by a $3.3 million decrease in gas revenues allocated to the investor partners within our investment partnerships for the six months ended June 30, 2011 compared with the prior year period. Total oil revenues were $9.2 million for the six months ended June 30, 2011, an increase of $0.4 million from $8.8 million for the comparable prior year period. This increase resulted primarily from a $0.8 million increase from the sale of natural gas liquids and a $1.0 million increase associated with higher average realized prices, partially offset by a $1.4 million decrease associated with lower oil production volumes.
Appalachia production costs were $7.1 million for the six months ended June 30, 2011, a decrease of $3.0 million from $10.1 million for the six months ended June 30, 2010. This decrease was principally due to a $1.3 million decrease in transportation costs, a $1.2 million decrease associated with water hauling and disposal costs and a $1.2 million decrease associated with labor, maintenance expenses and other costs associated with our gas and oil operations, partially offset by a $0.7 million decrease associated with our proportionate share of lease operating expenses associated with our revenue that was allocated to the investor partners within our investment partnerships. New Albany/Antrim production
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costs were $0.9 million for the six months ended June 30, 2011, an increase of $0.4 million from $0.5 million for the comparable prior year period. This increase was primarily attributable to a $0.2 million increase for labor-related expense and a $0.2 million increase associated with parts, materials and other costs associated with our increased natural gas production in New Albany/Antrim.
PARTNERSHIP MANAGEMENT
Well Construction and Completion
Drilling Program Results. The number of wells we drill will vary within the partnership management segment depending on the amount of capital we raise through our investment partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of drilling partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells we drilled for our investment partnerships during the three and six months ended June 30, 2011 and 2010. There were no exploratory wells drilled during the three and six months ended June 30, 2011 and 2010:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Drilling partnership investor capital: | ||||||||||||||||
Raised | $ | — | $ | 29,417 | $ | — | $ | 29,417 | ||||||||
Deployed | $ | 10,954 | $ | 43,295 | $ | 28,679 | $ | 115,937 | ||||||||
Gross partnership wells drilled: | ||||||||||||||||
Appalachia | — | — | 3 | 10 | ||||||||||||
New Albany/Antrim | — | 27 | — | 27 | ||||||||||||
Niobrara | — | — | 17 | — | ||||||||||||
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Total | — | 27 | 20 | 37 | ||||||||||||
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Net partnership wells drilled: | ||||||||||||||||
Appalachia | — | — | 3 | 10 | ||||||||||||
New Albany/Antrim | — | 23 | — | 23 | ||||||||||||
Niobrara | — | — | 17 | — | ||||||||||||
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Total | — | 23 | 20 | 33 | ||||||||||||
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Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for investment partnerships we sponsor. The following table sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Average construction and completion: | ||||||||||||||||
Revenue per well | $ | 5,160 | $ | 2,062 | $ | 954 | $ | 2,108 | ||||||||
Cost per well | 4,373 | 1,747 | 809 | 1,786 | ||||||||||||
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Gross profit per well | $ | 787 | $ | 315 | $ | 145 | $ | 322 | ||||||||
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Gross profit margin | $ | 1,670 | $ | 6,613 | $ | 4,374 | $ | 17,694 | ||||||||
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Partnership net wells associated with revenue recognized(1): | ||||||||||||||||
Appalachia | 1 | 9 | 2 | 35 | ||||||||||||
New Albany/Antrim | 1 | 12 | 3 | 20 | ||||||||||||
Niobrara | — | — | 25 | — | ||||||||||||
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2 | 21 | 30 | 55 | |||||||||||||
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(1) | Consists of partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis. |
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Three Months Ended June 30, 2011 Compared with the Three Months Ended June 30, 2010.Well construction and completion segment margin was $1.7 million for the three months ended June 30, 2011, a decrease of $4.9 million from $6.6 million for the three months ended June 30, 2010. This decrease consisted of a $5.8 million decrease related to fewer wells recognized for revenue within the investment partnerships, partially offset by a $0.9 million increase associated with higher gross profit per well. Since our drilling contracts with the Drilling Partnerships are on a “cost-plus” basis (typically cost-plus 18%), an increase or decrease in our average cost per well also results in a proportionate increase or decrease in our average revenue per well, which directly affects the number of wells we drill. Average cost and revenue per well increased between periods due to higher capital deployed per Marcellus Shale horizontal well within the Drilling Partnerships during the second quarter 2011 in comparison to the prior year period. Additionally, the second quarter 2010 was characterized by more New Albany/Antrim Shale capital deployed, which have a lower cost per well as compared to the Marcellus Shale wells. In addition, the decrease in well construction and completion margin was the result of the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010.
Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010. Well construction and completion segment margin was $4.4 million for the six months ended June 30, 2011, a decrease of $13.3 million from $17.7 million for the six months ended June 30, 2010. This decrease consisted of a $5.2 million decrease associated with lower gross profit per well and a $8.1 million decrease related to fewer wells recognized for revenue within the investment partnerships. Average cost and revenue per well decreased between periods due to more capital deployed for Niobrara formation wells within the Drilling Partnerships during the first six months of 2011, while the first six months of 2010 was characterized by more Marcellus Shale capital deployed. Typically, the Niobrara formation wells we have drilled within the Drilling Partnerships have a lower cost per well as compared to the Marcellus Shale wells. In addition, the decrease in well construction and completion margin was the result of the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010.
Our consolidated combined balance sheet at June 30, 2011 includes $36.4 million of “liabilities associated with drilling contracts” for funds raised by our investment partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated combined statements of operations. We expect to recognize this amount as revenue during the remainder of 2011 and early 2012.
Administration and Oversight
Administration and oversight fee revenues represents supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for our investment partnerships.
Three Months Ended June 30, 2011 Compared with the Three Months Ended June 30, 2010.Administration and oversight fee revenues were $1.4 million for the three months ended June 30, 2011, a decrease of $0.5 million from $1.9 million for the three months ended June 30, 2010. This decrease was primarily due to a decrease in the number of New Albany Shale wells drilled during the current year period in comparison to the prior year period. In addition, the decrease in administration and oversight margin was the result of the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010.
Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010.Administration and oversight fee revenues were $2.7 million for the six months ended June 30, 2011, a decrease of $1.2 million from $3.9 million for the six months ended June 30, 2010. This decrease was primarily due to a decrease in the number of Marcellus Shale and New Albany Shale wells drilled during the current year period in comparison to the prior year period. In addition, the decrease in administration and oversight margin was the result of the cancellation of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010.
Well Services
Well service revenue and expenses represent the monthly operating fees we charge and the work our service company performs for our investment partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells in which we serve as operator.
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Three Months Ended June 30, 2011 Compared with the Three Months Ended June 30, 2010.Well services revenues were $4.9 million for the three months ended June 30, 2011, which were consistent with the three months ended June 30, 2010. Well services expenses were $1.7 million for three months ended June 30, 2011, a decrease of $1.1 million from $2.8 million for the three months ended June 30, 2010. The decrease in well services expense is primarily related to a reduction in repairs and maintenance expenses due to fewer wells turned in line during the three months ended June 30, 2011 as compared with the comparable prior year period.
Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010.Well services revenues were $10.1 million for the six months ended June 30, 2011, which were consistent with the six months ended June 30, 2010. Well services expenses were $4.0 million for six months ended June 30, 2011, a decrease of $1.3 million from $5.3 million for the six months ended June 30, 2010. The decrease in well services expense is primarily related to a reduction in repairs and maintenance expenses due to fewer wells turned in line during the six months ended June 30, 2011 as compared with the comparable prior year period.
Gathering and Processing
Gathering and processing margin includes gathering fees we charge to our investment partnership wells and the related expenses, gross margin for our processing plants in the New Albany Shale and the Chattanooga Shale, and the operating revenues and expenses of APL. The gathering fees charged to our investment partnership wells generally range from $0.35 per Mcf to the amount of the competitive gathering fee, currently defined as 13% of the gross sales price of the natural gas. In general, pursuant to gathering agreements we have with a third-party gathering system which gathers the majority of our natural gas, we must also pay an additional amount equal to the excess of the gathering fees collected from the investment partnerships up to an amount equal to approximately 16% of the realized natural gas sales price (adjusted for the settlement of natural gas derivative instruments). However, in most of our direct investment partnerships, we collect a gathering fee of 13% of the realized natural gas sales price per the respective partnership agreement. As a result, some of our gathering expenses within our partnership management segment, specifically those in the Appalachia Basin, will generally exceed the revenues collected from the investment partnerships by approximately 3%.
The following table presents our gathering and processing revenues and expenses and those attributable to APL for each of the respective periods:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Gathering and Processing: | 2011 | 2010(1) | 2011 | 2010(1) | ||||||||||||
Atlas Energy: | ||||||||||||||||
Revenue | $ | 5,118 | $ | 5,956 | $ | 9,617 | $ | 9,069 | ||||||||
Expense | (5,763 | ) | (7,798 | ) | (11,497 | ) | (12,053 | ) | ||||||||
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Gross Margin | $ | (645 | ) | $ | (1,842 | ) | $ | (1,880 | ) | $ | (2,984 | ) | ||||
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Atlas Pipeline: | ||||||||||||||||
Revenue | $ | 340,616 | $ | 208,060 | $ | 616,335 | $ | 441,493 | ||||||||
Expense | (287,708 | ) | (175,029 | ) | (518,958 | ) | (366,936 | ) | ||||||||
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Gross Margin | $ | 52,908 | $ | 33,031 | $ | 97,377 | $ | 74,557 | ||||||||
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Total: | ||||||||||||||||
Revenue | $ | 345,734 | $ | 214,016 | $ | 625,952 | $ | 450,562 | ||||||||
Expense | (293,471 | ) | (182,827 | ) | (530,455 | ) | (378,989 | ) | ||||||||
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Gross Margin | $ | 52,263 | $ | 31,189 | $ | 95,497 | $ | 71,573 | ||||||||
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(1) | Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010. |
Three Months June 30, 2011 Compared with the Three Months Ended June 30, 2010. Our net gathering and processing expense for the three months ended June 30, 2011 was $0.6 million compared with $1.8 million for the three months ended June 30, 2010. This favorable increase was principally due to higher gathering fees received and higher processing margins due to higher processing production volumes and natural gas liquids prices compared with the prior year period.
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Gathering and processing margin for APL was $52.9 million for the three months ended June 30, 2011 compared with $33.0 million for the three months ended June 30, 2010. This increase was due principally to higher average natural gas liquids and crude oil commodity prices between periods.
Six Months June 30, 2011 Compared with the Six Months Ended June 30, 2010. Our net gathering and processing expense for the six months ended June 30, 2011 was $1.9 million compared with $3.0 million for the six months ended June 30, 2010. This favorable increase was principally due to lower natural gas volume between the periods.
Gathering and processing margin for APL was $97.4 million for the six months ended June 30, 2011 compared with $74.6 million for the six months ended June 30, 2010. This increase was due principally to higher average natural gas liquids and crude oil commodity prices between periods.
Gain (Loss) on Mark-to-Market Derivatives
Three Months Ended June 30, 2011 Compared with the Three Months Ended June 30, 2010.Gain on mark-to-market derivatives was $6.8 million for the three months ended June 30, 2011 as compared with $5.8 million for the three months ended June 30, 2010. This favorable movement was due primarily to a $12.2 million favorable variance in non-cash mark-to-market adjustments on derivatives and a $16.7 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts in the prior period partially offset by a $15.6 million unfavorable movement in cash settlements on net cash derivative expense related to APL’s early termination of a portion of its derivative contracts and a $12.3 million unfavorable variance in non-cash derivative gains related to early termination of a portion of APL’s derivative contracts in the current period.
Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010.Loss on mark-to-market derivatives was $14.8 million for the six months ended June 30, 2011 as compared with a gain of $10.5 million for the six months ended June 30, 2010. This unfavorable movement was due primarily to a $19.7 million unfavorable variance in non-cash mark-to-market adjustments on derivatives, a $24.3 million unfavorable variance in non-cash derivative gains related to early termination of a portion of APL’s derivative contracts and a $15.9 million unfavorable movement in cash settlements on net cash derivative expense related to APL’s early termination of a portion of its derivative contracts partially offset by a $34.6 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts in the prior period.
Other, Net
Three Months Ended June 30, 2011 Compared with the Three Months Ended June 30, 2010.Other revenues were $21.4 million for the three months ended June 30, 2011 as compared with $2.2 million for the comparable prior year period. This favorable increase was due primarily to an $18.7 million increase in our equity earnings from Lightfoot. During the three months ended June 30, 2011, we recorded a gain of $17.6 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP, its metallurgical and steam coal business in March 2011.
Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010.Other revenues were $25.8 million for the six months ended June 30, 2011 as compared with $4.2 million for the comparable prior year period. This favorable increase was due primarily to a $19.8 million increase in our equity earnings from Lightfoot. During the six months ended June 30, 2011, we recorded a gain of $17.6 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP, its metallurgical and steam coal business in March 2011.
OTHER COSTS AND EXPENSES
General and Administrative Expenses
The following table presents our general and administrative expenses and those attributable to APL for each of the respective periods:
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Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010(1) | 2011 | 2010(1) | |||||||||||||
General and Administrative expenses: | ||||||||||||||||
Atlas Energy | $ | 13,669 | $ | 580 | $ | 20,842 | $ | 1,370 | ||||||||
Atlas Pipeline | 8,570 | 6,192 | 17,587 | 15,943 | ||||||||||||
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Total | $ | 22,239 | $ | 6,772 | $ | 38,429 | $ | 17,313 | ||||||||
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(1) | Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010. |
Total general and administrative expenses increased to $22.2 million for the three months ended June 30, 2011 compared with $6.8 million for the three months ended June 30, 2010. Because the Transferred Business was not accounted for by AEI as a stand-alone business unit, it was not practicable for us to allocate general and administrative expenses to it for historical periods. Therefore, the general and administrative expenses for the three and six months ended June 30, 2010 were comprised of our stand-alone general and administrative expenses, while the expenses for the three and six months ended June 30, 2011 were comprised of our stand-alone general and administration expenses and that of the Transferred Business. In addition, our general and administrative expenses for the three months ended June 30, 2011 included $6.2 million of reimbursements we received from Chevron for the transition services we provided during the period. Our $13.7 million of general and administrative expense for the three months ended June 30, 2011 was comprised of $6.2 million of net salary and wages expense, $4.1 million of non-cash compensation expense and $3.4 million of other corporate activities. APL’s $8.6 million of general and administrative expense for the three months ended June 30, 2011 represents an increase of $2.4 million from the comparable prior year period, which was principally due to an increase in salaries and wages resulting mainly from the expansion of its business.
Total general and administrative expenses increased to $38.4 million for the six months ended June 30, 2011 compared with $17.3 million for the six months ended June 30, 2010. Our general and administrative expenses for the six months ended June 30, 2011 included $9.2 million of reimbursements we received from Chevron for the transition services we provided during the period. Our $20.8 million of general and administrative expense for the six months ended June 30, 2011 was comprised of $6.4 million of net salary and wages expense, $4.6 million of non-cash compensation expense, $2.8 million of syndication expenses related to the cancellation of our Fall 2010 drilling program, $2.1 million of transaction costs related to the acquisition of the Transferred Business, and $4.9 million of other corporate activities. APL’s $17.6 million of general and administrative expense for the six months ended June 30, 2011 represents an increase of $1.7 million from the comparable prior year period, which was principally due to an increase in salaries and wages resulting mainly from the expansion of its business.
Depreciation, Depletion and Amortization
The following table presents our depreciation, depletion and amortization expense and that which was attributable to APL for each of the respective periods:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010(1) | 2011 | 2010(1) | |||||||||||||
Depreciation, depletion and amortization: | ||||||||||||||||
Atlas Energy | $ | 8,247 | $ | 11,491 | $ | 15,948 | $ | 20,131 | ||||||||
Atlas Pipeline | 19,123 | 18,624 | 38,029 | 37,081 | ||||||||||||
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Total | $ | 27,370 | $ | 30,115 | $ | 53,977 | $ | 57,212 | ||||||||
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(1) | Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010. |
Total depreciation, depletion and amortization decreased to $27.4 million for the three months ended June 30, 2011 compared with $30.1 million for the comparable prior year period primarily due to a $1.7 million decrease in our depletion expense.
Total depreciation, depletion and amortization decreased to $54.0 million for the six months ended June 30, 2011 compared with $57.2 million for the comparable prior year period primarily due to a $3.1 million decrease in our depletion expense. The following table presents our depletion expense, excluding amounts attributable to APL, per Mcfe for our operations for the respective periods:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Depletion expense (in thousands): | ||||||||||||||||
Total | $ | 7,178 | $ | 8,938 | $ | 13,744 | $ | 16,835 |
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Depletion expense as a percentage of gas and oil production revenue | 41 | % | 35 | % | 39 | % | 33 | % | ||||||||
Depletion per Mcfe | $ | 2.15 | $ | 2.36 | $ | 2.06 | $ | 2.19 |
Depletion expense varies from period to period and is directly affected by changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. For the three months ended June 30, 2011, depletion expense decreased $1.7 million to $7.2 million compared with $8.9 million for the three months ended June 30, 2010. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 41% for the three months ended June 30, 2011, compared with 35% for the three months ended June 30, 2010, which was primarily due to a decrease in realized natural gas prices between periods. Depletion expense per Mcfe was $2.15 for the three months ended June 30, 2011, a decrease of $0.21 per Mcfe from $2.36 for the three months ended June 30, 2010. Depletion expense decreased between periods principally due to an overall decrease in production volumes combined with the $49.7 million impairment of our Chattanooga Shale field recorded during the three months ended December 31, 2010.
For the six months ended June 30, 2011, depletion expense decreased $3.1 million to $13.7 million compared with $16.8 million for the six months ended June 30, 2010. Our depletion expense of oil and gas properties as a percentage of oil and gas revenues was 39% for the six months ended June 30, 2011, compared with 33% for the six months ended June 30, 2010, which was primarily due to a decrease in realized natural gas prices between periods. Depletion expense per Mcfe was $2.06 for the six months ended June 30, 2011, a decrease of $0.13 per Mcfe from $2.19 for the six months ended June 30, 2010. Depletion expense decreased between periods principally due to an overall decrease in production volumes combined with the $49.7 million impairment of our Chattanooga Shale field recorded during the three months ended December 31, 2010.
Gain (Loss) on Asset Sales
The $255.7 million of gain on asset sales for the six months ended June 30, 2011 principally represents APL’s gain on sale of its 49% non-controlling interest in the Laurel Mountain joint venture. The $2.9 million loss on asset sales for the six months ended June 30, 2010 represents the loss recognized on APL’s sale of a processing plant.
Interest Expense
The following table presents our interest expense and that which was attributable to APL for each of the respective periods:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010(1) | 2011 | 2010(1) | |||||||||||||
Interest Expense: | ||||||||||||||||
Atlas Energy | $ | 423 | $ | 524 | $ | 6,056 | $ | 1,142 | ||||||||
Atlas Pipeline | 6,144 | 24,595 | 18,589 | 50,998 | ||||||||||||
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Total | $ | 6,567 | $ | 25,119 | $ | 24,645 | $ | 52,140 | ||||||||
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(1) | Restated to reflect amounts reclassified to discontinued operations due to the sale of certain APL assets in September 2010. |
Total interest expense decreased to $6.6 million for the three months ended June 30, 2011 as compared with $25.1 million for the three months ended June 30, 2010. This $18.5 million decrease was due to an $18.4 million decrease related to APL and our $0.1 million decrease. Our $0.4 million of interest expense for the three months ended June 30, 2011 is comprised of $0.2 million of commitment fees related to the unused portion of our credit facility and $0.2 million in amortization of deferred financing costs. The $18.4 million decrease in interest expense for APL was primarily due to a $7.3 million decrease in interest expense associated with its term loan, a $5.2 million decrease in interest expense associated with its 8.125% Senior Notes and a $4.3 million decrease in interest expense associated with its revolving credit facility. In April 2011, APL completed the redemption of all of its 8.125% Senior Notes for a total redemption of $293.7 million and also purchased $7.2 million, or 3.24%, of its outstanding 8.75% Senior Notes. APL funded the redemptions as well as the repayment of borrowings under its revolving credit facility with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain (see “Recent Developments”). APL also repaid a portion of its term loan and borrowings under its revolving credit facility with the net proceeds from the sale of its Elk City processing and gathering system in September 2010.
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Total interest expense decreased to $24.6 million for the six months ended June 30, 2011 as compared with $52.1 million for the six months ended June 30, 2010. This $27.5 million decrease was primarily due to a $32.4 million decrease related to APL, partially offset by our $4.9 million increase. Our $4.9 million increase in interest expense was primarily due to $4.9 million of accelerated amortization of deferred financing costs for our interim bridge credit facility that was used for the acquisition of the Transferred Business. This credit facility was terminated and replaced in March 2011. The $32.4 million decrease in interest expense for APL was primarily due to a $14.5 million decrease in interest expense associated with its term loan, a $9.0 million decrease in interest expense associated with its revolving credit facility and a $5.2 million decrease in interest expense associated with its 8.125% Senior Notes.
Loss on early extinguishment of debt for the three and six months ended June 30, 2011 represents the premium paid for the redemption of the APL 8.125% Senior Notes and APL’s recognition of deferred finance costs related to the redemption (see “–Recent Developments”).
Income (Loss) from Discontinued Operations
For the three months ended June 30, 2011, there was no income (loss) from discontinued operations. For the three months ended June 30, 2010, income from discontinued operations, which consists of amounts associated with APL’s Elk City system that was sold in September 2010, was $8.0 million.
For the six months ended June 30, 2011, income (loss) from discontinued operations, which consists of amounts associated with APL’s Elk City system was $0.1 million. For the six months ended June 30, 2010, income from discontinued operations, which consists of amounts associated with APL’s Elk City system that was sold in September 2010 was $14.8 million.
Income Not Attributable to Common Limited Partners
For the three months ended June 30, 2010, income not attributable to common limited partners was $15.8 million, which consists of income not attributable to common limited partners related to the results of operations of the Transferred Business prior to our acquisition on February 17, 2011. For the six months ended June 30, 2011 and 2010, income not attributable to common limited partners was $4.7 million and $40.3 million, respectively, which consists of income not attributable to common limited partners related to the results of operations of the Transferred Business prior to our acquisition on February 17, 2011.
(Income) Loss Attributable to Non-Controlling Interests
Income attributable to non-controlling interests was $7.9 million for the three months ended June 30, 2011 compared with income of $0.7 million for the comparable prior year period. Income attributable to non-controlling interests was $219.3 million for the six months ended June 30, 2011 compared with income of $2.5 million for the comparable prior year period. Income attributable to non-controlling interests includes an allocation of APL’s net income (loss) to non-controlling interest holders. This change was primarily due to an increase in APL’s net earnings between periods, including the gain from the sale of its investment in Laurel Mountain.
LIQUIDITY AND CAPITAL RESOURCES
General
Our primary sources of liquidity are cash generated from operations, capital raised through investment partnerships, and borrowings under our credit facility (see “Recent Developments”). Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to our common unitholders. In general, we expect to fund:
• | Cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities; |
• | Expansion capital expenditures and working capital deficits through cash generated from operations, additional borrowings and capital raised through investment partnerships; and |
• | Debt principal payments through additional borrowings as they become due or by the issuance of additional common units or asset sales. |
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We rely on cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. We believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we are subject to business, operational and other risks that could adversely affect our cash flow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional common units, the sale of assets and other transactions.
Cash Flows – Six Months Ended June 30, 2011 Compared with the Six Months Ended June 30, 2010
Net cash provided by operating activities of $58.3 million for the six months ended June 30, 2011 represented an unfavorable movement of $19.6 million from net cash provided by operating activities of $77.9 million for the comparable prior year period. The decrease was derived principally from a $36.3 million increase in distributions paid to non-controlling interests, $4.5 million unfavorable movement in net income from discontinued operations and a $0.9 million decrease in net income excluding non-cash items, partially offset by a $12.4 million favorable movement in working capital and a $9.6 million increase in distributions received from unconsolidated subsidiaries. The non-cash charges which impacted net income include a $240.6 million increase in net income from continuing operations, a $20.4 million favorable movement in non-cash expenses, including loss on early extinguishment of debt, compensation expense, depreciation, depletion and amortization and amortization of deferred financing costs and a favorable movement in non-cash gain on derivatives of $12.1 million, partially offset by a $258.7 million unfavorable movement in gains on asset sales. The increase in net income from continuing operations was primarily due to a $255.7 million gain on the sale of APL’s interest in Laurel Mountain, partially offset by a decrease in well construction and completion margin due to the absence of our fall 2010 drilling program, which was the result of our announcement of the acquisition of the Transferred Business in November 2010. The movement in non-cash derivative losses resulted from increases in commodity prices from January 1, 2010 through June 30, 2010 and their $6.8 million favorable impact on the fair value of derivative contracts we and APL had for future periods. The movement in cash distributions to non-controlling interest holders was due principally to increases in the cash distributions of APL. The movement in working capital was principally due to a $89.7 million favorable movement in accounts payable and other current liabilities, partially offset by a $77.3 million unfavorable movement in accounts receivable and other current assets.
Net cash provided by investing activities of $206.1 million for the six months ended June 30, 2011 represented a favorable movement of $283.4 million from net cash used in investing activities of $77.3 million for the comparable prior year period. This favorable movement was principally due to a $411.3 million increase in net proceeds from asset sales and a $4.4 million favorable movement in net cash used in discontinued operations, partially offset by a $85.3 million unfavorable movement in investments in our and APL’s unconsolidated subsidiaries, including APL’s 20% investment in the West Texas LPG Pipeline, a $44.3 million unfavorable movement in capital expenditures and a $2.8 million unfavorable movement in other assets. See further discussion of capital expenditures under “- Capital Requirements”.
Net cash used in financing activities of $155.8 million for the six months ended June 30, 2011 represented a change of $154.3 million from $1.5 million for the comparable prior year period. This movement was principally due to $321.7 million of repayments of long-term debt, a $15.3 million decrease in net proceeds from equity offerings, a $31.2 million movement in net investment received from AEI prior to February 17, 2011, and a $6.4 million change in other financing activities, partially offset by $120.9 million non-cash transaction adjustment related to the acquisition of the Transferred Business and a $121.5 million change in net borrowings under our and APL’s credit facilities.
Capital Requirements
Our capital requirements consist primarily of:
• | maintenance capital expenditures — capital expenditures we make on an ongoing basis to maintain our capital asset base at a steady level; and |
• | expansion capital expenditures — capital expenditures we make to expand our capital asset base for longer than the short-term and includes new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in our drilling partnerships. |
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Atlas Pipeline Partners.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 our consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010(1) | 2011 | 2010(1) | |||||||||||||
Atlas Energy | ||||||||||||||||
Maintenance capital expenditures | $ | 3,567 | $ | — | $ | 5,233 | $ | — | ||||||||
Expansion capital expenditures | 3,083 | 13,851 | 9,149 | 42,256 | ||||||||||||
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Total | $ | 6,650 | $ | 13,851 | $ | 14,382 | $ | 42,256 | ||||||||
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Atlas Pipeline | ||||||||||||||||
Maintenance capital expenditures | $ | 5,211 | $ | 3,008 | $ | 8,471 | $ | 3,883 | ||||||||
Expansion capital expenditures | 68,425 | 10,040 | 83,498 | 15,952 | ||||||||||||
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Total | $ | 73,636 | $ | 13,048 | $ | 91,969 | $ | 19,835 | ||||||||
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Consolidated Combined | ||||||||||||||||
Maintenance capital expenditures | $ | 8,778 | $ | 3,008 | $ | 13,704 | $ | 3,883 | ||||||||
Expansion capital expenditures | 71,508 | 23,891 | 92,647 | 58,208 | ||||||||||||
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Total | $ | 80,286 | $ | 26,899 | $ | 106,351 | $ | 62,091 | ||||||||
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(1) | Restated to reflect amounts reclassified to discontinued operations due to the sales of certain APL assets in September 2010. |
During the three months ended June 30, 2011, our $6.7 million of total capital expenditures consisted primarily of $3.1 million of well costs, principally our investments in the Drilling Partnerships, compared with $11.5 million for the prior year comparable period, $0.7 million in leasehold acquisition costs compared with $0.6 million for the prior year comparable period, $1.3 million of gathering and processing costs compared with $1.0 million for the prior year comparable period, and $1.6 million of corporate and other compared with $0.1 million for the prior year comparable period. Maintenance capital expenditures, which are the component of total capital expenditures that maintain our capital asset base at a steady level and is based upon the estimated cost to replace the reserves produced during the respective period, were $3.6 million during the three months ended June 30, 2011. Prior to our acquisition of the Transferred Business on February 17, 2011, we had no maintenance capital requirements with regard to our oil and gas properties.
During the six months ended June 30, 2011, our $14.4 million of total capital expenditures consisted primarily of $7.1 million of well costs, principally our investments in the Drilling Partnerships, compared with $27.0 million for the prior year comparable period, $1.4 million in leasehold acquisition costs compared with $6.2 million for the prior year comparable period, $2.4 million of gathering and processing costs compared with $7.2 million for the prior year comparable period and $3.0 million of corporate and other compared with $0.9 million for the prior year comparable period. Maintenance capital expenditures were $5.2 million during the six months ended June 30, 2011. Prior to our acquisition of the Transferred Business on February 17, 2011, we had no maintenance capital requirements with regard to our oil and gas properties.
We continuously evaluate acquisitions of gas and oil assets. In order to make any acquisition, we believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we will be successful in our efforts to obtain outside capital.
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Atlas Pipeline Partners. APL’s capital expenditures increased to $73.6 million for the three months ended June 30, 2011 compared with $13.0 million for the comparable prior year period. The increase was due principally to costs incurred related to APL’s processing facility expansions, compressor upgrades and pipeline projects.
APL’s capital expenditures increased to $92.0 million for the six months ended June 30, 2011 compared with $19.8 million for the comparable prior year period. The increase was due principally to costs incurred related to APL’s processing facility expansions, compressor upgrades and pipeline projects.
As of June 30, 2011, we and APL are committed to expend approximately $271.3 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.
OFF BALANCE SHEET ARRANGEMENTS
As of June 30, 2011, our and APL’s off-balance sheet arrangements are limited to our letters of credit outstanding of $0.8 million, APL’s letters of credit outstanding of $1.7 million and commitments to spend $271.3 million related to our drilling and completion expenditures and our and APL’s capital expenditures.
CASH 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. 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.
APL’S CASH 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, 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. Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights as set forth in the IDR Adjustment Agreement.
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CREDIT FACILITY
On March 22, 2011, we entered into a new credit facility with a syndicate of banks that matures in March 2016. The credit facility has maximum lender commitments of $300 million and a current borrowing base of $160 million. The borrowing base is redetermined semiannually in May and November subject to changes in oil and gas reserves and is automatically reduced by 25% of the stated principal of any senior unsecured notes we issued. Our borrowing base was increased by the lending group to $160.0 million from $125.0 million upon its regularly scheduled May 2011 redetermination. Up to $20.0 million of the credit facility may be in the form of standby letters of credit. The facility is secured by substantially all of our assets and is guaranteed by substantially all of our subsidiaries (excluding APL and its subsidiaries). The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter ending on or after June 30, 2011. Based on the definitions contained in the Partnership’s credit facility, its ratio of current assets to current liabilities was 2.5 to 1.0, its ratio of Total Funded Debt to EBITDA was 0.01 to 1.0 and its ratio of EBITDA to Total Interest Expense was 64.5 to 1.0 at June 30, 2011.
ISSUANCE OF UNITS
Pursuant to prevailing accounting literature, we recognize gains on our APL’s equity transactions as a credit to partners’ capital rather than as income. These gains represent our portion of the excess net offering price per unit of each of APL’s common units over the book carrying amount per unit.
In February 2011, we paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on the Partnership’s common limited partner unit’s February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million (see “Recent Developments”).
Atlas Pipeline Partners
In June 2010, APL sold 8,000 newly-created 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) to AEI for cash consideration of $1,000 per APL Class C Preferred Unit (the “Face Value”). The APL Class C Preferred Units were redeemable by APL for an amount equal to the Face Value of the units being redeemed plus all accrued but unpaid dividends. AEI was entitled to distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. On February 17, 2011, the APL Class C Preferred Units were acquired from AEI by Chevron as part of AEI’s merger with Chevron. On May 27, 2011, APL redeemed all 8,000 APL Class C Preferred Units outstanding for cash at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividend on the 8,000 APL Class C Preferred Units prior to APL’s redemption. APL no longer has any APL Class C Preferred Units outstanding.
In January 2010, APL executed amendments to warrants to purchase 2,689,765 of its common units. The warrants were originally issued along with its common units in connection with a private placement to institutional investors that closed in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants agreed to exercise all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility.
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
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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, depletion, 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 combined financial statements was included within our Audit Report on Form 10-K for the year ended December 31, 2010 and in Note 2 under Item 1, “Financial Statements” included in this report, and there have been no material changes to these policies through June 30, 2011.
Fair Value of Financial Instruments
We have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
We use a fair value methodology to value the assets and liabilities for our and APL’s outstanding derivative contracts. Our and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. 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 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.
Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.
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 principally of our ownership interests in our subsidiaries, the following information principally encompasses their 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 the market risk sensitive instruments were entered into for purposes other than trading.
General
All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.
We and our subsidiaries 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 our
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subsidiaries manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on June 30, 2011. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.
Current market conditions elevate our and our subsidiaries’ concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our commodity and interest-rate derivative contracts are banking institutions or their affiliates, who also participate in our revolving credit facilities. The creditworthiness of our counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our counterparties to perform under their contracts and believe our exposure to non-performance is remote.
Interest Rate Risk.At June 30, 2011, we had no outstanding borrowings under our $160.0 million revolving credit facility. At June 30, 2011, APL had $142.5 million of outstanding borrowings under its $350.0 million senior secured revolving credit facility (on July 8, 2011, the revolving credit facility was increased to $450 million - see “–Subsequent Events”). Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated combined interest expense, net of non-controlling interests, by $0.2 million.
Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas, NGLs, condensate and oil and the impact those price movements have on the financial results of our subsidiaries. To limit our exposure to changing natural gas and oil prices, we use financial derivative instruments for a portion of our future natural gas and oil production. 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. APL enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under these 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. 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 period.
Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated combined operating income from continuing operations attributable to common limited partners for the twelve-month period ending June 30, 2011 of approximately $5.1 million.
Realized pricing of our oil and natural gas production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we enter into natural gas and oil swap and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.
At June 30, 2011, we had the following commodity derivatives:
Natural Gas Fixed Price Swaps
Production Period Ending December 31, | Volumes | Average Fixed Price | ||||||
(mmbtu)(1) | (per mmbtu) (1) | |||||||
2011 | 3,120,000 | $ | 4.484 | |||||
2012 | 5,520,000 | $ | 5.000 | |||||
2013 | 3,120,000 | $ | 5.288 | |||||
2014 | 2,880,000 | $ | 5.590 | |||||
2015 | 2,880,000 | $ | 5.861 |
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Natural Gas Costless Collars
Production Period Ending December 31, | Option Type | Volumes | Average Floor and Cap | |||||||
(mmbtu)(1) | (per mmbtu) (1) | |||||||||
2011 | Puts purchased | 1,620,000 | $ | 3.933 | ||||||
2011 | Calls sold | 1,620,000 | $ | 5.584 | ||||||
2012 | Puts purchased | 1,920,000 | $ | 4.250 | ||||||
2012 | Calls sold | 1,920,000 | $ | 6.084 | ||||||
2013 | Puts purchased | 3,120,000 | $ | 4.750 | ||||||
2013 | Calls sold | 3,120,000 | $ | 6.065 |
Crude Oil Costless Collars
Production Period Ending December 31, | Option Type | Volumes | Average Floor and Cap | |||||||
(Bbl) (1) | (per Bbl) (1) | |||||||||
2011 | Puts purchased | 30,000 | $ | 90.000 | ||||||
2011 | Calls sold | 30,000 | $ | 125.312 | ||||||
2012 | Puts purchased | 60,000 | $ | 90.000 | ||||||
2012 | Calls sold | 60,000 | $ | 117.912 | ||||||
2013 | Puts purchased | 60,000 | $ | 90.000 | ||||||
2013 | Calls sold | 60,000 | $ | 116.396 | ||||||
2014 | Puts purchased | 24,000 | $ | 80.000 | ||||||
2014 | Calls sold | 24,000 | $ | 121.250 | ||||||
2015 | Puts purchased | 24,000 | $ | 80.000 | ||||||
2015 | Calls sold | 24,000 | $ | 120.750 |
(1) | “Mmbtu” represents million British Thermal Units; “Bbl” represents barrels. |
As of June 30, 2011, APL had the following commodity derivatives:
Fixed Price Swaps
Production Period | Purchased/ | Commodity | Volumes | Average Fixed Price | ||||||||
Natural Gas | ||||||||||||
2011 | Sold | Natural Gas Basis | 960,000 | (0.728 | ) | |||||||
2011 | Purchased | Natural Gas Basis | 960,000 | (0.758 | ) | |||||||
2011 | Sold | Natural Gas Basis | 2,400,000 | 4.723 | ||||||||
Natural Gas Liquids | ||||||||||||
2011 | Sold | Propane | 8,568,000 | 1.176 | ||||||||
2011 | Sold | Isobutane | 1,008,000 | 1.618 | ||||||||
2011 | Sold | Normal Butane | 2,772,000 | 1.580 | ||||||||
2011 | Sold | Natural Gasoline | 6,552,000 | 2.042 | ||||||||
2012 | Sold | Propane | 19,278,000 | 1.302 | ||||||||
2012 | Sold | Normal Butane | 2,520,000 | 1.906 | ||||||||
2012 | Sold | Natural Gasoline | 4,158,000 | 2.401 | ||||||||
Crude Oil | ||||||||||||
2011 | Sold | Crude Oil | 60,000 | 90.680 | ||||||||
2012 | Sold | Crude Oil | 180,000 | 103.770 | ||||||||
Total Fixed Price Swaps |
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Options
Production Period | Purchased/ | Commodity | Volumes(1) | Average Strike Price | ||||||||
Natural Gas | ||||||||||||
2011 | Purchased | Propane | 10,206,000 | $ | 1.309 | |||||||
2012 | Purchased | Propane | 20,160,000 | $ | 1.399 | |||||||
Crude Oil | ||||||||||||
2011 | Purchased | Crude Oil | 192,000 | 98.121 | ||||||||
2011 | Sold | Crude Oil | 339,000 | 93.354 | ||||||||
2011 | Purchased(2) | Crude Oil | 126,000 | 125.200 | ||||||||
2012 | Purchased | Crude Oil | 156,000 | 105.003 | ||||||||
2012 | Sold | Crude Oil | 498,000 | 94.694 | ||||||||
2012 | Purchased(2) | Crude Oil | 180,000 | 125.200 | ||||||||
2013 | Purchased(2) | Crude Oil | 282,000 | 100.100 |
(1) | Volumes for natural gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels. |
(2) | Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise. |
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 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 and with the participation of our management, including of our Chief Executive Officer and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2011, our disclosure controls and procedures were effective at the reasonable assurance level.
On February 17, 2011, we acquired certain producing natural gas and oil properties, an investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. In addition, in connection with this acquisition, we have installed the management team that managed the Transferred Business under AEI into our organization, including our Chief Executive Officer and Chief Financial Officer, and adopted AEI’s internal controls over financial reporting under which the Transferred Business operated. However, we continue to integrate these internal controls into our internal control structure. This integration may lead to changes in our internal control over financial reporting in future fiscal reporting periods. Other than the previously mentioned item, 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
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Exhibit No. | Description | |
2.1 | Transaction Agreement, by and among Atlas Energy, Inc., Atlas Energy Resources, LLC, Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010. (21) | |
2.2 | Purchase and Sale Agreement, by and among Atlas Pipeline Partners, L.P., APL Laurel Mountain, LLC, Atlas Energy, Inc., and Atlas Energy Resources, LLC, dated November 8, 2010. (21) | |
2.3 | Employee Matters Agreement, by and among Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Pipeline Holdings GP, LLC, dated November 8, 2010. (21) | |
3.1 | Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.(1) | |
3.2 | Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(13) | |
3.3 | Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.(13) | |
3.4 | Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.(13) | |
4.1 | Specimen Certificate Representing Common Units(1) | |
10.1 | Certificate of Formation of Atlas Pipeline Holdings GP, LLC(1) | |
10.2 | Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC. (13) | |
10.3(a) | Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(1) | |
10.3(b) | Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1) | |
10.3(c) | Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(4) | |
10.3(d) | Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.3(e) | Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.3(f) | Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.3(g) | Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(7) | |
10.3(h) | Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(14) | |
10.3(i) | Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(15) | |
10.4(a) | Long-Term Incentive Plan(6) | |
10.4(b) | Amendment No. 1 to Long-Term Incentive Plan(26) | |
10.5 | 2010 Long-Term Incentive Plan(16) | |
10.6 | Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan(25) | |
10.7 | Form of Stock Option Grant under 2010 Long-Term Incentive Plan(25) | |
10.8(a) | Amended and Restated Credit Agreement, dated July 27, 2007, amended and restated as of December 22, 2010, among Atlas Pipeline Partners, L.P., the guarantors therein, Wells Fargo Bank, National Association, and other banks party thereto(23) | |
10.8(b) | Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011 (27) |
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Exhibit No. | Description | |
10.8(c) | Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011 (28) | |
10.9 | Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12) | |
10.10 | Petro-Technical Services Agreement, dated as of February 17, 2011 between Atlas Energy, Inc. and Atlas Pipeline Holdings, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12) | |
10.11(a) | Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12) | |
10.11(b) | Amendment No. 1 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of January 6, 2011. (12) | |
10.11(c) | Amendment No. 2 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of February 2, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12) | |
10.12 | Transaction Confirmation, Supply Contract No. 0001, under Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated February 17, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12) | |
10.13 | Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12) | |
10.14 | Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12) | |
10.15 | Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011(12) | |
10.16 | Employment Agreement between Atlas Energy, L.P. and Jonathon Z. Cohen dated as of May 13, 2011(12) | |
10.17 | Securities Purchase Agreement, dated July 27, 2010, by and among Atlas Pipeline Mid-Continent, LLC, Atlas Pipeline Partners, L.P., Enbridge Pipelines (Texas Gathering) L.P. and Enbridge Energy Partners, L.P.(18) |
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Exhibit No. | Description | |
10.18 | Letter Agreement, dated as of August 31, 2009, between Atlas America, Inc. and Eric Kalamaras(12) | |
10.19 | Phantom Unit Grant Agreement between Atlas Pipeline Mid-Continent, LLC and Eric Kalamaras, dated September 14, 2009(12) | |
10.20 | Form of Grant of Phantom Units to Non-Employee Managers(20) | |
10.21 | Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010(21) | |
10.22 | Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010(22) | |
10.23 | Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010(22) | |
10.24 | Credit Agreement, dated as of March 22, 2011, among Atlas Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto(24) | |
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 | |
101.INS | XBRL Instance Document(29) | |
101.SCH | XBRL Schema Document(29) | |
101.CAL | XBRL Calculation Linkbase Document(29) | |
101.LAB | XBRL Label Linkbase Document(29) | |
101.PRE | XBRL Presentation Linkbase Document(29) | |
101.DEF | XBRL Definition Linkbase Document(29) |
(1) | Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999). |
(2) | [Intentionally omitted] |
(3) | [Intentionally omitted] |
(4) | Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007. |
(5) | [Intentionally omitted] |
(6) | Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008. |
(7) | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009. |
(8) | [Intentionally omitted] |
(9) | [Intentionally omitted] |
(10) | Previously filed as an exhibit to current report on Form 8-K filed June 1, 2009. |
(11) | [Intentionally omitted] |
(12) | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011. |
(13) | Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2011. |
(14) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 2, 2010. |
(15) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 7, 2010. |
(16) | Previously filed as an exhibit to current report on Form 8-K filed on November 12, 2010. |
(17) | [Intentionally omitted] |
(18) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 29, 2010. |
(19) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on September 1, 2010. |
(20) | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2010. |
(21) | Previously filed as an exhibit to current report on Form 8-K filed November 12, 2010. |
(22) | Previously filed as an exhibit to Atlas Energy, Inc.’s current report on Form 8-K filed on November 12, 2010. |
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(23) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 23, 2010. |
(24) | Previously filed as an exhibit to current report on Form 8-K filed on March 25, 2011. |
(25) | Previously filed as an exhibit to the registration statement on Form S-8 filed on March 25, 2011. |
(26) | Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2010. |
(27) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011. |
(28) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 11, 2011. |
(29) | Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.” |
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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 ENERGY, L.P. | ||||||||
By: | Atlas Energy GP, LLC, its General Partner | |||||||
Date: August 5, 2011 | By: | /s/ EDWARD E. COHEN | ||||||
Edward E. Cohen | ||||||||
Chief Executive Officer and President | ||||||||
Date: August 5, 2011 | By: | /s/ SEAN P. MCGRATH | ||||||
Sean P. McGrath | ||||||||
Chief Financial Officer | ||||||||
Date: August 5, 2011 | By: | /s/ JEFFREY M. SLOTTERBACK | ||||||
Jeffrey M. Slotterback | ||||||||
Chief Accounting Officer |
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