UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. 1)
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2012
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: 001-32953
ATLAS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 43-2094238 | |
(State or other jurisdiction or incorporation or organization) | (I.R.S. Employer Identification No.) | |
Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA | 15275 | |
(Address of principal executive offices) | Zip code |
Registrant’s telephone number, including area code: 412-489-0006
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common Units representing Limited Partnership Interests | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Title of class
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
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 definitions of “large accelerated filer”, “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ | 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 aggregate market value of the voting and non-voting common units held by non-affiliates of the registrant, based on the closing price of such units on the last business day of the registrant’s most recently completed second quarter, June 30, 2012, was approximately $1.5 billion.
The number of outstanding common units of the registrant on February 25, 2013 was 51,370,560.
DOCUMENTS INCORPORATED BY REFERENCE: None
EXPLANATORY NOTE
This Amendment No. 1 on Form 10-K/A (the “Amendment”) amends Atlas Energy, L.P.’s (the “Partnership”) Annual Report on Form 10-K for the year ended December 31, 2012, as originally filed with the Securities and Exchange Commission on March 1, 2013 (the “Original Filing”). The Partnership is filing the Amendment due to staff comments from the United States Securities and Exchange Commission solely to amend and restate:
(a) Part II—Item 8 “Financial Statements and Supplementary Data” to revise the consolidated combined statements of comprehensive income (loss) of the Partnership and subsidiaries to reorder certain line items and subtotals presented, separately disclose the amounts of total other comprehensive income (loss), consolidated comprehensive income (loss), including amounts attributable to the common limited partners and attributable to non-controlling interests, and to revise certain headings in such financial statements;
(b) Part II—Item 9A “Controls and Procedures” to include a discussion of a material weakness identified subsequent to the Original Filing and to provide an updated Report of Independent Registered Public Accounting Firm that references the updated auditor report provided in Item 8 of the Amendment; and
(c) Part IV—Item 15 “Exhibits and Financial Statement Schedules” to indicate that new auditor consents and new certifications by the Partnership’s general partner’s principal executive and principal financial officers, as required by Rule 12b-15, are filed as exhibits to the Amendment.
This Amendment does not affect any other parts of, or exhibits to, the Original Filing, nor does it reflect events occurring after the date of the Original Filing. The previously reported amounts of comprehensive income (loss) attributable to common limited partners did not change for any period.
2
ITEM 8: | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Unitholders
Atlas Energy, L.P.
We have audited the accompanying consolidated balance sheets of Atlas Energy, L.P. (a Delaware limited partnership) and subsidiaries (collectively the “Partnership”) as of December 31, 2012 and 2011, and the related consolidated combined statements of operations, comprehensive income (loss), changes in partners’ capital, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated combined financial statements referred to above present fairly, in all material respects, the financial position of Atlas Energy, L.P. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 23, the consolidated combined statements of comprehensive income (loss) for the years ended December 31, 2012, 2011 and 2010 have been restated to correct an error.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2012, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2013 (except for the material weakness and the effects thereof discussed in Management’s Report on Internal Control over Financial Reporting, as revised, as to which the date is October 22, 2013) expressed an adverse opinion.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
February 28, 2013 (except as disclosed in Note 23, as to which the date is October 22, 2013)
3
ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, | ||||||||
2012 | 2011 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 36,780 | $ | 77,376 | ||||
Accounts receivable | 196,249 | 136,853 | ||||||
Current portion of derivative asset | 35,351 | 15,447 | ||||||
Subscriptions receivable | 55,357 | 34,455 | ||||||
Prepaid expenses and other | 45,255 | 24,779 | ||||||
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Total current assets | 368,992 | 288,910 | ||||||
Property, plant and equipment, net | 3,502,609 | 2,093,283 | ||||||
Intangible assets, net | 200,680 | 104,777 | ||||||
Investment in joint venture | 86,002 | 86,879 | ||||||
Goodwill, net | 351,069 | 31,784 | ||||||
Long-term derivative asset | 16,840 | 30,941 | ||||||
Other assets, net | 71,002 | 48,197 | ||||||
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$ | 4,597,194 | $ | 2,684,771 | |||||
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LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 10,835 | $ | 2,085 | ||||
Accounts payable | 119,028 | 93,554 | ||||||
Liabilities associated with drilling contracts | 67,293 | 71,719 | ||||||
Accrued producer liabilities | 109,725 | 88,096 | ||||||
Current portion of derivative payable to Drilling Partnerships | 11,293 | 20,900 | ||||||
Accrued interest | 11,556 | 1,629 | ||||||
Accrued well drilling and completion costs | 47,637 | 17,585 | ||||||
Accrued liabilities | 103,291 | 61,653 | ||||||
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Total current liabilities | 480,658 | 357,221 | ||||||
Long-term debt, less current portion | 1,529,508 | 522,055 | ||||||
Long-term derivative liability | 888 | — | ||||||
Long-term derivative payable to Drilling Partnerships | 2,429 | 15,272 | ||||||
Deferred income taxes, net | 30,258 | — | ||||||
Asset retirement obligations and other | 73,605 | 46,142 | ||||||
Commitments and contingencies | ||||||||
Partners’ Capital: | ||||||||
Common limited partners’ interests | 456,171 | 554,999 | ||||||
Accumulated other comprehensive income | 9,699 | 29,376 | ||||||
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465,870 | 584,375 | |||||||
Non-controlling interests | 2,013,978 | 1,159,706 | ||||||
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Total partners’ capital | 2,479,848 | 1,744,081 | ||||||
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$ | 4,597,194 | $ | 2,684,771 | |||||
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See accompanying notes to consolidated combined financial statements
4
ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Revenues: | ||||||||||||
Gas and oil production | $ | 92,901 | $ | 66,979 | $ | 93,050 | ||||||
Well construction and completion | 131,496 | 135,283 | 206,802 | |||||||||
Gathering and processing | 1,219,815 | 1,329,418 | 944,609 | |||||||||
Administration and oversight | 11,810 | 7,741 | 9,716 | |||||||||
Well services | 20,041 | 19,803 | 20,994 | |||||||||
Gain (loss) on mark-to-market derivatives | 31,940 | (20,453 | ) | (5,944 | ) | |||||||
Other, net | 13,440 | 31,803 | 17,437 | |||||||||
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Total revenues | 1,521,443 | 1,570,574 | 1,286,664 | |||||||||
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Costs and expenses: | ||||||||||||
Gas and oil production | 26,624 | 17,100 | 23,323 | |||||||||
Well construction and completion | 114,079 | 115,630 | 175,247 | |||||||||
Gathering and processing | 1,009,100 | 1,123,051 | 789,548 | |||||||||
Well services | 9,280 | 8,738 | 10,822 | |||||||||
General and administrative | 165,777 | 80,584 | 37,561 | |||||||||
Chevron transaction expense | 7,670 | — | — | |||||||||
Depreciation, depletion and amortization | 142,611 | 109,373 | 115,655 | |||||||||
Asset impairment | 9,507 | 6,995 | 50,669 | |||||||||
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Total costs and expenses | 1,484,648 | 1,461,471 | 1,202,825 | |||||||||
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Operating income | 36,795 | 109,103 | 83,839 | |||||||||
Gain (loss) on asset sales and disposal | (6,980 | ) | 256,292 | (13,676 | ) | |||||||
Interest expense | (46,520 | ) | (38,394 | ) | (90,448 | ) | ||||||
Loss on early extinguishment of debt | — | (19,574 | ) | (4,359 | ) | |||||||
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Income (loss) from continuing operations before tax | (16,705 | ) | 307,427 | (24,644 | ) | |||||||
Income tax expense | 176 | — | — | |||||||||
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Income (loss) from continuing operations | (16,881 | ) | 307,427 | (24,644 | ) | |||||||
Discontinued operations: | ||||||||||||
Gain from sale of discontinued operations | — | — | 312,102 | |||||||||
Income (loss) from discontinued operations | — | (81 | ) | 9,053 | ||||||||
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Net income (loss) | (16,881 | ) | 307,346 | 296,511 | ||||||||
Income attributable to non-controlling interests | (35,532 | ) | (257,643 | ) | (245,764 | ) | ||||||
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Income (loss) after non-controlling interests | (52,413 | ) | 49,703 | 50,747 | ||||||||
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 | ) | (22,813 | ) | |||||||
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Net income (loss) attributable to common limited partners | $ | (52,413 | ) | $ | 44,992 | $ | 27,934 | |||||
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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 | $ | (1.02 | ) | $ | 0.91 | $ | (0.43 | ) | ||||
Income from discontinued operations attributable to common limited partners | — | — | 1.44 | |||||||||
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Net income (loss) attributable to common limited partners | $ | (1.02 | ) | $ | 0.91 | $ | 1.01 | |||||
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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 | $ | (1.02 | ) | $ | 0.88 | $ | (0.43 | ) | ||||
Income from discontinued operations attributable to common limited partners | — | — | 1.44 | |||||||||
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Net income (loss) attributable to common limited partners | $ | (1.02 | ) | $ | 0.88 | $ | 1.01 | |||||
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Weighted average common limited partner units outstanding: | ||||||||||||
Basic | 51,327 | 48,235 | 27,718 | |||||||||
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Diluted | 51,327 | 49,676 | 27,718 | |||||||||
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Income (loss) attributable to common limited partners: | ||||||||||||
Income (loss) from continuing operations | $ | (52,413 | ) | $ | 45,002 | $ | (11,994 | ) | ||||
Income (loss) from discontinued operations | — | (10 | ) | 39,928 | ||||||||
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Net income (loss) attributable to common limited partners | $ | (52,413 | ) | $ | 44,992 | $ | 27,934 | |||||
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See accompanying notes to consolidated combined financial statements
5
ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
(As Restated)
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Net income (loss) | $ | (16,881 | ) | $ | 307,346 | $ | 296,511 | |||||
Other comprehensive income (loss): | ||||||||||||
Changes in fair value of derivative instruments accounted for as cash flow hedges | 10,921 | 35,156 | 25,801 | |||||||||
Less: reclassification adjustment for realized gains of cash flow hedges in net income (loss) | (14,891 | ) | (3,708 | ) | 1,343 | |||||||
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Total other comprehensive income (loss) | (3,970 | ) | 31,448 | 27,144 | ||||||||
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Comprehensive income (loss) | (20,851 | ) | 338,794 | 323,655 | ||||||||
Comprehensive income attributable to non-controlling interests | (51,239 | ) | (263,597 | ) | (278,612 | ) | ||||||
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 the acquisition (see Note 2)) | — | (4,711 | ) | (22,813 | ) | |||||||
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Comprehensive income (loss) attributable to common limited partners | $ | (72,090 | ) | $ | 70,486 | $ | 22,230 | |||||
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See accompanying notes to consolidated combined financial statements
6
ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(in thousands, except unit data)
Common Limited Partners’ Capital | Accumulated Other Comprehensive Income | Non- Controlling Interest | Total Partners’ Capital | |||||||||||||||||
Units | Amount | |||||||||||||||||||
Balance at January 1, 2010 | 27,703,579 | $ | 339,283 | $ | 9,586 | $ | 704,986 | $ | 1,053,855 | |||||||||||
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3) | — | 25,627 | — | — | 25,627 | |||||||||||||||
Issuance of common units to the public | — | — | — | 15,319 | 15,319 | |||||||||||||||
Issuance of common units under incentive plans | 131,675 | — | — | 156 | 156 | |||||||||||||||
Atlas Pipeline Partners, L.P. distributions to non-controlling interests | — | — | — | (23,236 | ) | (23,236 | ) | |||||||||||||
Unissued common units under incentive plans | — | 1,245 | — | 3,484 | 4,729 | |||||||||||||||
Other comprehensive (loss) income | — | — | (5,704 | ) | 32,918 | 27,214 | ||||||||||||||
Repurchase and retirement of common limited partner units | — | — | — | (246 | ) | (246 | ) | |||||||||||||
Distributions paid to common limited partners | — | (1,385 | ) | — | — | (1,385 | ) | |||||||||||||
Distribution equivalent rights paid on unissued units under incentive plans | — | (7 | ) | — | (174 | ) | (181 | ) | ||||||||||||
Atlas Pipeline Partners, L.P. preferred unit distribution | — | — | — | (240 | ) | (240 | ) | |||||||||||||
Atlas Pipeline Partners, L.P. issuance of preferred units | — | — | — | 8,000 | 8,000 | |||||||||||||||
Net loss on purchase and sale of Atlas Pipeline Partners, L.P. equity | — | (2,456 | ) | — | 2,456 | — | ||||||||||||||
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)) | — | 22,813 | — | — | 22,813 | |||||||||||||||
Net income | — | 27,934 | — | 245,764 | 273,698 | |||||||||||||||
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Balance at December 31, 2010 | 27,835,254 | $ | 413,054 | $ | 3,882 | $ | 989,187 | $ | 1,406,123 | |||||||||||
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) | — | (261,042 | ) | — | — | (261,042 | ) | |||||||||||||
Atlas Pipeline Partners, L.P. distributions to non-controlling interests | — | — | — | (87,094 | ) | (87,094 | ) | |||||||||||||
Unissued common units under incentive plans | — | 13,101 | — | 3,003 | 16,104 | |||||||||||||||
Issuance of units under incentive plans | 63,724 | 167 | — | 468 | 635 | |||||||||||||||
Distributions paid to common limited partners | — | (31,164 | ) | — | — | (31,164 | ) | |||||||||||||
Distribution equivalent rights paid on unissued units under incentive plans | — | (1,020 | ) | — | (764 | ) | (1,784 | ) | ||||||||||||
Atlas Pipeline Partners, L.P. preferred unit distribution | — | — | — | (629 | ) | (629 | ) | |||||||||||||
Atlas Pipeline Partners, L.P. preferred unit redemption | — | — | — | (8,000 | ) | (8,000 | ) | |||||||||||||
Other comprehensive income | — | — | 25,494 | 5,892 | 31,386 | |||||||||||||||
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 | — | 44,992 | — | 257,643 | 302,635 | |||||||||||||||
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Balance at December 31, 2011 | 51,278,362 | $ | 554,999 | $ | 29,376 | $ | 1,159,706 | $ | 1,744,081 | |||||||||||
Distribution of Atlas Resource Partners, L.P. units | — | (84,892 | ) | — | 84,892 | — | ||||||||||||||
Distributions to non-controlling interests | — | — | — | (120,456 | ) | (120,456 | ) | |||||||||||||
Unissued common units under incentive plan | — | 17,579 | — | 22,218 | 39,797 | |||||||||||||||
Issuance of units under incentive plans | 87,220 | 258 | — | 128 | 386 | |||||||||||||||
Non-controlling interests’ capital contribution | — | — | — | 804,768 | 804,768 | |||||||||||||||
Atlas Pipeline Partners L.P. purchase price allocation | — | — | — | 89,440 | 89,440 | |||||||||||||||
Atlas Pipeline Partners L.P. purchase and retirement of treasury stock | — | — | — | (695 | ) | (695 | ) | |||||||||||||
Distributions paid to common limited partners | — | (51,837 | ) | — | — | (51,837 | ) | |||||||||||||
Distribution equivalent rights paid on unissued units under incentive plans | — | (2,070 | ) | — | (2,715 | ) | (4,785 | ) | ||||||||||||
Gain on sale of subsidiary units | — | 74,547 | — | (74,547 | ) | — | ||||||||||||||
Other comprehensive income (loss) | — | — | (19,677 | ) | 15,707 | (3,970 | ) | |||||||||||||
Net income (loss) | — | (52,413 | ) | — | 35,532 | (16,881 | ) | |||||||||||||
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Balance at December 31, 2012 | 51,365,582 | $ | 456,171 | $ | 9,699 | $ | 2,013,978 | $ | 2,479,848 | |||||||||||
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See accompanying notes to consolidated combined financial statements
7
ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
Net income (loss) | $ | (16,881 | ) | $ | 307,346 | $ | 296,511 | |||||
Income (loss) from discontinued operations | — | (81 | ) | 321,155 | ||||||||
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Income (loss) from continuing operations | (16,881 | ) | 307,427 | (24,644 | ) | |||||||
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization | 142,611 | 109,373 | 115,655 | |||||||||
Asset impairment | 9,507 | 6,995 | 50,669 | |||||||||
Amortization of deferred financing costs | 6,720 | 5,105 | 10,618 | |||||||||
Non-cash (gain) loss on derivative value, net | (31,335 | ) | 16,312 | 4,609 | ||||||||
Non-cash compensation expense | 40,300 | 16,104 | 4,729 | |||||||||
(Gain) loss on asset sales and disposal | 6,980 | (256,292 | ) | 13,676 | ||||||||
Deferred income tax expense | 176 | — | — | |||||||||
Loss on early extinguishment of debt | — | 19,574 | 4,359 | |||||||||
Distributions paid to non-controlling interests | (123,171 | ) | (87,857 | ) | (23,410 | ) | ||||||
Equity income in unconsolidated companies | (7,863 | ) | (21,582 | ) | (6,701 | ) | ||||||
Distributions received from unconsolidated companies | 8,131 | 20,643 | 11,784 | |||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable and prepaid expenses and other | (53,973 | ) | (66,251 | ) | (5,640 | ) | ||||||
Accounts payable and accrued liabilities | 89,074 | 18,725 | (21,825 | ) | ||||||||
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Net cash provided by continuing operating activities | 70,276 | 88,276 | 133,879 | |||||||||
Net cash provided by (used in) discontinued operating activities | — | (81 | ) | 23,374 | ||||||||
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Net cash provided by operating activities | 70,276 | 88,195 | 157,253 | |||||||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Capital expenditures | (500,759 | ) | (292,750 | ) | (139,360 | ) | ||||||
Net cash paid for acquisitions | (1,150,150 | ) | — | — | ||||||||
Investments in unconsolidated companies | — | (97,250 | ) | (26,514 | ) | |||||||
Net proceeds from asset disposals | — | 403,668 | (2,019 | ) | ||||||||
Other | 404 | 491 | 1,031 | |||||||||
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Net cash provided by (used in) continuing investing activities | (1,650,505 | ) | 14,159 | (166,862 | ) | |||||||
Net cash provided by discontinued investing activities | — | — | 669,192 | |||||||||
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Net cash provided by (used in) investing activities | (1,650,505 | ) | 14,159 | 502,330 | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Borrowings under credit facilities | 1,846,599 | 1,585,500 | 482,000 | |||||||||
Repayments under credit facilities | (1,335,174 | ) | (1,513,500 | ) | (746,000 | ) | ||||||
Net proceeds from issuance of Atlas Pipeline Partners, L.P.’s long-term debt | 495,374 | 152,366 | — | |||||||||
Repayments of long-term debt | — | (329,314 | ) | (433,505 | ) | |||||||
Net proceeds from subsidiary equity offerings | 611,606 | — | 15,475 | |||||||||
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 unitholders | (51,837 | ) | (31,164 | ) | (1,385 | ) | ||||||
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3) | — | 111,158 | 25,627 | |||||||||
Deferred financing costs and other | (26,935 | ) | 7,729 | (10,651 | ) | |||||||
|
|
|
|
|
| |||||||
Net cash provided by (used in) financing activities | 1,539,633 | (25,225 | ) | (660,439 | ) | |||||||
Net change in cash and cash equivalents | (40,596 | ) | 77,129 | (856 | ) | |||||||
Cash and cash equivalents, beginning of year | 77,376 | 247 | 1,103 | |||||||||
|
|
|
|
|
| |||||||
Cash and cash equivalents, end of year | $ | 36,780 | $ | 77,376 | $ | 247 | ||||||
|
|
|
|
|
|
See accompanying notes to consolidated combined financial statements
8
ATLAS ENERGY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS
NOTE 1 – BASIS OF PRESENTATION
Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS).
At December 31, 2012, the Partnership’s operations primarily consisted of its ownership interests in the following entities:
• | Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At December 31, 2012, the Partnership owned 100% of the general partner Class A units and incentive distribution rights, and common units representing an approximate 43.0% limited partner ownership interest in ARP; |
• | Atlas Pipeline Partners, L.P. (“APL”), a publicly-traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services throughout the southwestern region of the United States. At December 31, 2012, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 8.7% common limited partner interest in APL; 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 December 31, 2012, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 8). |
In February 2012, the board of directors of the Partnership’s General Partner (“the Board”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of the Partnership’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to the Partnership’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.
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 December 31, 2012 except for ARP and APL, which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP and APL, the Partnership consolidates the financial statements of ARP and APL into its consolidated combined financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP and APL are reflected as (income) loss attributable to non-controlling interests in its consolidated combined statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated. Certain amounts in the prior year’s consolidated combined financial statements have been reclassified to conform to the current year presentation. Due to changes in business as a result of the formation of ARP during the year ended December 31, 2012, management of the Partnership modified its reportable operating segments. As a result, management of the Partnership reclassified the operating segment data for the years ended December 31, 2011 and 2010 to be consistent with the year ended December 31, 2012 (see Note 19).
On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, the partnership management business, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of the Partnership’s general partner (see Note 3). Management of the Partnership determined that the acquisition of the
9
Transferred Business constituted a transaction between entities under common control. In comparison to the acquisition 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 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 on the Partnership’s consolidated balance sheets. Also, in comparison to the acquisition 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; |
• | Retrospectively adjusted its consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect its results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and |
• | Adjusted the presentation of the Partnership’s consolidated combined statements of operations for the year ended December 31, 2011 and 2010 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income 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. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business. |
In accordance with established practice in the oil and gas industry, the Partnership’s consolidated combined 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 ARP has an interest (“the Drilling Partnerships”). Such interests typically range from 20% to 41%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP 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 West OK natural gas gathering system and processing plants and a 72.8% undivided interest in the West TX 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 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 balance sheets.
The West TX joint venture has a 72.8% undivided joint venture interest in the West TX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the West TX system’s status as an undivided joint venture, the West TX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the West TX system.
The Partnership’s consolidated combined financial statements also include APL’s 60% interest in Centrahoma Processing LLC (“Centrahoma”), which was acquired on December 20, 2012 as part of the acquisition of assets from Cardinal Midstream, LLC (“Cardinal Acquisition”) (see Note 4). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly- owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). APL consolidates 100% of this joint venture and the non-controlling interest in the joint venture is reflected on the Partnership’s consolidated combined statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint ventures within partners’ capital on its consolidated balance sheets (see Note 4).
10
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 number of significant estimates, including 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 and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition. Actual results could differ from those estimates.
Cash Equivalents
The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.
Receivables
Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with ARP’s and APL’s operations. In evaluating the realizability of its accounts receivable, management of ARP and APL performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of ARP’s and APL’s customers’ credit information. ARP and APL extend credit on sales on an unsecured basis to many of its customers. At December 31, 2012 and 2011, ARP and APL had recorded no allowance for uncollectible accounts receivable on the Partnership’s consolidated balance sheets.
Inventory
ARP and APL had $13.5 million and $16.0 million of inventory at December 31, 2012 and 2011, respectively, which were included within prepaid expenses and other current assets on the Partnership’s consolidated balance sheets. ARP values inventories at the lower of cost or market. ARP’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 consist of APL’s natural gas liquids line fill, which represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then current market price.
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. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components 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, processing and treating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and treating components, is recorded to accumulated depreciation.
ARP 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 and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.
11
ARP’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 ARP’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.
Upon the sale or retirement of an ARP complete field of a proved property, the cost is eliminated 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 ARP well, ARP credits the proceeds to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon ARP’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.
Impairment of Long-Lived Assets
The Partnership and its subsidiaries review their 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 ARP’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 ARP’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. ARP 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, ARP’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 ARP’s actual capital contributions, an additional carried interest (generally 5% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.
ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’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. ARP cannot predict what reserve revisions may be required in future periods.
ARP’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 ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP 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 ARP 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 ARP.
12
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 that ARP 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 gas and oil properties recorded by ARP for the years ended December 31, 2012, 2011 and 2010.
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2012, the Partnership recognized $9.5 million of asset impairment related to ARP’s gas and oil properties within property, plant and equipment on its consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara Shales. During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to ARP’s gas and oil properties within property, plant and equipment on its consolidated balance sheet for its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, the Partnership recognized $50.7 million of asset impairment related to ARP’s gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the Chattanooga and Upper Devonian Shales. These impairments related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair value at December 31, 2012, 2011 and 2010. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
Capitalized Interest
ARP and APL 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 interest rates used to capitalize interest on combined borrowed funds by ARP and APL in the aggregate were 5.8%, 7.0% and 7.5% for the years ended December 31, 2012, 2011 and 2010, respectively. The aggregate amounts of interest capitalized by ARP and APL were $10.8 million, $5.1 million and $0.8 million for the years ended December 31, 2012, 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. APL completed the Cardinal Acquisition (see Note 4) and other acquisitions of various gas gathering systems and related assets during the year ended December 31, 2012. APL accounted for these acquisitions as business combinations and recognized $119.9 million related to customer contracts with an estimated useful life of 10-14 years. Due to the recent date of the Cardinal Acquisition, the accounting for the business combination has not been completed. The estimates of fair value reflected as of December 31, 2012 are subject to change and changes could be material.
Partnership management and operating contracts. ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.
The following table reflects the components of intangible assets being amortized at December 31, 2012 and 2011 (in thousands):
Estimated Useful Lives In Years | ||||||||||
December 31, | ||||||||||
2012 | 2011 | |||||||||
Gross Carrying Amount: | ||||||||||
Customer contracts and relationships | $ | 325,246 | $ | 205,313 | 7 – 14 | |||||
Partnership management and operating contracts | 14,344 | 14,344 | 13 | |||||||
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| |||||||
$ | 339,590 | $ | 219,657 | |||||||
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|
| |||||||
Accumulated Amortization: | ||||||||||
Customer contracts and relationships | $ | (125,886 | ) | $ | (102,037 | ) | ||||
Partnership management and operating contracts | (13,024 | ) | (12,843 | ) | ||||||
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|
| |||||||
$ | (138,910 | ) | $ | (114,880 | ) | |||||
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|
|
| |||||||
Net Carrying Amount: | ||||||||||
Customer contracts and relationships | $ | 199,360 | $ | 103,276 | ||||||
Partnership management and operating contracts | 1,320 | 1,501 | ||||||||
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|
|
| |||||||
$ | 200,680 | $ | 104,777 | |||||||
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13
Amortization expense on intangible assets was $24.0 million, $23.8 million and $23.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2013 - $35.8 million; 2014 - $32.2 million; 2015 - $27.2 million; 2016 - $26.6 million; and 2017 - $20.3 million.
Goodwill
At December 31, 2012, the Partnership recorded $351.1 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $319.3 million related to APL’s acquisitions during the year ended December 31, 2012, of which $310.9 million related to the Cardinal Acquisition (see Note 4). The goodwill related to the Cardinal Acquisition is a result of the strategic industry position and potential future synergies. At December 31, 2011, the Partnership had $31.8 million of goodwill recorded in connection with prior ARP consummated acquisitions. There were no changes in the carrying amount of goodwill for ARP for the years ended December 31, 2012, 2011 and 2010 and there was no goodwill recorded for APL for the years ended December 31, 2011 and 2010.
ARP and APL test 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, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s and APL’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 and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to 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 ARP’s and APL’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, ARP and APL also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s and APL’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s and APL’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the years ended December 31, 2012, 2011 and 2010, no impairment indicators arose and no goodwill impairments were recognized for ARP by the Partnership. At December 31, 2012, due to the recent date of the Cardinal Acquisition, APL completed a qualitative test of its recorded goodwill and there was no indication of impairment. Thus, no quantitative analysis was performed for the year ended December 31, 2012. No goodwill impairments charges were recognized for APL for the years ended December 31, 2012, 2011 and 2010.
Capital Leases
Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 10).
14
Derivative Instruments
ARP and APL enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 11). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in ARP’s and APL’s derivative instrument’s fair value are recognized currently in the Partnership’s consolidated combined statements of operations unless specific hedge accounting criteria are met.
Asset Retirement Obligations
ARP recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 9). ARP also recognizes a liability for its future asset retirement obligations in the current period 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 and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.
Income Taxes
The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated combined financial statements.
The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated combined financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its consolidated combined financial statements as of December 31, 2012, 2011 and 2010.
The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2012 except for: 1) an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through 2011 and 2) an examination by the IRS related to one of APL’s corporate subsidiaries’ Federal Corporate Return for the period ended December 31, 2011.
Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. With the exception of a corporate subsidiary acquired by APL through the Cardinal Acquisition (see Note 4), the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated combined financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying consolidated combined financial statements. APL’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to APL earnings that are generally not subject to federal and state income taxes at the APL level (see Note 13).
Stock-Based Compensation
The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated combined financial statements based on their fair values (see Note 18).
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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 18), 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 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 (loss) 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 unit data):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Continuing operations: | ||||||||||||
Net income (loss) | $ | (16,881 | ) | $ | 307,427 | $ | (24,644 | ) | ||||
(Income) loss attributable to non-controlling interests | (35,532 | ) | (257,714 | ) | 35,463 | |||||||
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 | ) | (22,813 | ) | |||||||
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Net income (loss) attributable to common limited partners | (52,413 | ) | 45,002 | (11,994 | ) | |||||||
Less: Net income attributable to participating securities – phantom units(1) | — | (1,243 | ) | — | ||||||||
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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 | $ | (52,413 | ) | $ | 43,759 | $ | (11,994 | ) | ||||
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Discontinued operations: | ||||||||||||
Net income (loss) | $ | — | $ | (81 | ) | $ | 321,155 | |||||
(Income) loss attributable to non-controlling interests | — | 71 | (281,227 | ) | ||||||||
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Net income (loss) utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit | $ | — | $ | (10 | ) | $ | 39,928 | |||||
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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 years ended December 31, 2012 and 2010 net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,058,000 and 130,000 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 18).
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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):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Weighted average number of common limited partners per unit - basic | 51,327 | 48,235 | 27,718 | |||||||||
Add effect of dilutive incentive awards(1) | — | 1,441 | — | |||||||||
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Weighted average number of common limited partners per unit - diluted | 51,327 | 49,676 | 27,718 | |||||||||
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(1) | For the years ended December 31, 2012 and 2010, approximately 2,867,000 units and 180,000 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. |
Environmental Matters
The Partnership and its subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s and its subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership and its subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. During the year ended December 31, 2012, one of the Partnership’s subsidiaries entered into two agreements with the United States Environmental Protection Agency (the “EPA”) to settle alleged violations (see Note 15). The Partnership and its subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the year ended December 31, 2011.
Concentration of Credit Risk
Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership and its subsidiaries place its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2012 and 2011, the Partnership and its subsidiaries had $51.4 million and $88.0 million, respectively, in deposits at various banks, of which $48.8 million and $82.1 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.
ARP and APL sell natural gas, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2012, ARP had two customers that individually accounted for approximately 43% and 11%, respectively, of its natural gas and oil consolidated combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2011, ARP had three customers that individually accounted for approximately 17%, 14% and 10% respectively, of its natural gas and oil consolidated combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2010, ARP had four customers that individually accounted for approximately 13%, 12%, 12% and 11%, of its natural gas and oil consolidated combined revenues, excluding the impact of all financial derivative activity.
For the year ended December 31, 2012, APL had two customers that individually accounted for approximately 48% and 15% of its consolidated total third-party revenues, respectively, excluding the impact of all financial derivative activity. For the year ended December 31, 2011, APL had two customers that individually accounted for approximately 60% and 16% of its consolidated total third-party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2010, APL had two customers that individually accounted for approximately 58% and 17% of its consolidated total third-party revenues, excluding the impact of all financial derivative activity. Additionally, APL had two customers that individually accounted for 45% and 14%, respectively, of its accounts receivable at December 31, 2012, and two customers that individually accounted for 56% and 15%, respectively, of its accounts receivable at December 31, 2011.
Revenue Recognition
Atlas Resource. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships must pay ARP 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 270 days. On an uncompleted contract, ARP 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
17
Partnership’s consolidated balance sheets. ARP recognizes well services revenues at the time the services are performed. ARP is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within the Partnership’s consolidated combined statements of operations.
ARP generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, ARP’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed 2 business days prior to the commencement of the production month. Revenue and the related accounts receivable are 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 and NGLs, in which ARP has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing, treating and transportation 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 NGLs, if any, at 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 and NGLs is recognized upon physical delivery. In connection with its gathering, processing and transportation 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 and for transporting NGLs. APL’s revenue is a function of the volume of natural gas that it gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. APL is also paid a separate compression fee on many of its gathering 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. |
• | Percentage of Proceeds (“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 processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBtu. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The Btu quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the Btu quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in Btu quantity. 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 Btu quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/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 help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in Btu content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic. |
ARP and APL accrue 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 ARP’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). ARP and APL had unbilled revenues at December 31, 2012 and 2011 of $134.2 million and $81.2 million, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.
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Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.
Recently Adopted Accounting Standards
In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-01,Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities(“Update 2013-01”). Update 2013-1 clarifies that ordinary trade receivables and receivables are not in the scope of ASU No. 2011-11,Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in theFASB Accounting Standards Codification (“Codification”) or subject to a master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.
In August 2012, the FASB issued ASU 2012-03,Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update)(“Update 2012-03”). Update 2012-03 codified amendments and corrections to the ASC for various Securities and Exchange Commission (“SEC”) paragraphs pursuant or related to 1) the issuance of Staff Accounting Bulletin (“SAB”) 114; 2) the SEC’s Final Rule,Technical Amendments to Commission Rules and Forms Related to the FASB’s Accounting Standards Codification, Release No. 3350-9250, 34-65052, and IC-29748 August 8, 2011; 3) ASU 2010-22,Accounting for Various Topics—Technical Corrections to SEC Paragraphs (SEC Update);and 4) other various status sections. The Partnership adopted the requirements of Update 2012-03 on September 30, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.
In December 2011, the FASB issued ASU 2011-12,Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05(“Update 2011-12”). The amendments in this update effectively defer the implementation of the changes made in Update 2011-05,Comprehensive Income (Topic 220): Presentation of Comprehensive Income(“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided 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. Under each methodology, 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. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included consolidated combined statements of comprehensive income (loss) within its March 31, 2012 Form 10-Q upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.
In December 2011, the FASB issued ASU 2011-11,Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities(“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities
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subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership has elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012 (see Note 11). The adoption had no material impact on the Partnership’s financial position or results of operations.
In September 2011, the FASB issued ASU 2011-08,Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment(“Update 2011-08”). The amendments in Update 2011-08 allow an entity to first assess qualitative factors in determining the necessity of performing the two-step quantitative goodwill impairment test. If, after assessing qualitative factors, an entity determines it is not likely that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. Under the amendments in Update 2011-08, an entity has the option to bypass the qualitative assessment and proceed directly to performing the first step of the two-step impairment test. The amendments are effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Partnership adopted the amendments of Update 2011-08 upon its effective date of January 1, 2012. The adoption had no material impact on the Partnership’s financial position or results of operations.
In May 2011, the FASB issued ASU 2011-04,Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (see Note 12). The adoption had no material impact on the Partnership’s financial position or results of operations.
Recently Issued Accounting Standards
In February 2013, the FASB issued ASU No. 2013-02,Comprehensive Income (Topic 220)(“Update 2013-02”).Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership will apply the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
In July 2012, the FASB issued ASU 2012-02,Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment(“Update 2012-02”). The amendments in Update 2012-02 allow an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. The “more likely than not” threshold is defined as having a likelihood of more than 50 percent. If, after assessing qualitative factors, an entity determines it is not likely that the indefinite-lived intangible asset is impaired, then no further action is required. If impairment is deemed more likely than not, the entity is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount of the asset. Additionally, under the amendments in Update 2012-02, an entity has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption being permitted. The Partnership will apply the requirements of Update 2012-02 upon its effective date of January 1, 2013, 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, including the following exploration and production assets that were transferred to ARP on March 5, 2012:
• | AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which ARP funds 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; and |
• | certain producing natural gas and oil properties, upon which ARP is the developer and producer. |
In addition to the exploration and production assets, the Transferred Business also included all of the ownership interests in Atlas Energy GP, LLC, the Partnership’s general partner, and a direct and indirect ownership interest in Lightfoot.
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. Concurrent with the Partnership’s acquisition of the Transferred Business, AEI was sold to Chevron Corporation (NYSE: CVX) (“Chevron”). In connection with the transaction, the Partnership received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain exploration and production liabilities assumed by the Partnership. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million. Certain amounts included within the contractual cash transaction adjustment were subject to a reconciliation period with Chevron following the consummation of the transaction. Liabilities related to the cash transaction adjustment were assumed by ARP on March 5, 2012, as certain amounts included within the contractual cash transaction adjustment remained in dispute between the parties. During the year ended December 31, 2012, ARP recognized a $7.7 million charge on the Partnership’s consolidated combined statement of operations regarding its reconciliation process with Chevron, which was settled in October 2012.
Concurrent with the Partnership’s acquisition of the Transferred Business on February 17, 2011, including assets and liabilities transferred to ARP on March 5, 2012, AEI completed its merger with 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 Laurel Mountain Midstream, LLC (“Laurel Mountain”; see Note 5). 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.
Management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. 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 on its consolidated balance sheet. The Partnership recognized a non-cash decrease of $261.0 million in partners’ capital on its consolidated 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 by the Partnership, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):
Cash | $ | 153,350 | ||
Accounts receivable | 18,090 | |||
Accounts receivable – affiliate | 45,682 | |||
Prepaid expenses and other | 6,955 | |||
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Total current assets | 224,077 | |||
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 | |||
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Total assets acquired | $ | 795,009 | ||
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Accounts payable | $ | 59,202 | ||
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 | |||
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Total current liabilities | 197,625 | |||
Long-term derivative payable to Drilling Partnerships | 31,719 | |||
Asset retirement obligations | 42,791 | |||
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Total long-term liabilities | 74,510 | |||
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Total liabilities assumed | $ | 272,135 | ||
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Historical carrying value of net assets acquired | $ | 522,874 | ||
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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 – ACQUISITIONS
ARP’s DTE Acquisition
On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, LLC from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million, subject to certain post-closing adjustments (the “DTE Acquisition”). In connection with entering into a purchase agreement related to the DTE Acquisition, ARP issued approximately 7.9 million of its common limited partner units through a public offering in November 2012 for $174.5 million, which was used to partially repay amounts outstanding under its revolving credit facility prior to closing (see Note 16). The cash paid at closing was funded through $179.8 million of borrowings under ARP’s revolving credit facility and $77.6 million through borrowings under ARP’s term loan credit facility (see Note 10).
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 12). In conjunction with the issuance of common units associated with the acquisition, ARP recorded $0.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s consolidated balance sheets. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date.
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):
Assets: | ||||
Accounts receivable | $ | 10,721 | ||
Prepaid expenses and other | 2,415 | |||
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Total current assets | 13,136 | |||
Property, plant and equipment | 261,023 | |||
Other assets, net | 273 | |||
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Total assets acquired | $ | 274,432 | ||
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Liabilities: | ||||
Accounts payable | $ | 5,904 | ||
Accrued liabilities | 2,910 | |||
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Total current liabilities | 8,814 | |||
Asset retirement obligation and other | 8,169 | |||
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Total liabilities assumed | 16,983 | |||
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Net assets acquired | $ | 257,449 | ||
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ARP’s Titan Acquisition
On July 25, 2012, ARP completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million common units and 3.8 million newly-created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 16). The cash paid at closing was funded through borrowings under ARP’s credit facility. The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) (see Note 16). The Partnership accounted for the issuance of ARP’s common and preferred limited partner units in exchange for the Titan assets acquired as a non-cash item in its consolidated combined statement of cash flows for the year ended December 31, 2012.
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 12). In conjunction with its issuance of common and preferred limited partner units associated with the acquisition, ARP recorded $3.5 million of transaction fees, which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s consolidated balance sheets. All other costs associated with the acquisition of assets were expensed as incurred.
The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):
Assets: | ||||
Cash and cash equivalents | $ | 372 | ||
Accounts receivable | 5,253 | |||
Prepaid expenses and other | 131 | |||
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| |||
Total current assets | 5,756 | |||
Natural gas and oil properties | 208,491 | |||
Other assets, net | 2,344 | |||
|
| |||
Total assets acquired | $ | 216,591 | ||
|
| |||
Liabilities: | ||||
Accounts payable | $ | 676 | ||
Revenue distribution payable | 3,091 | |||
Accrued liabilities | 1,816 | |||
|
| |||
Total current liabilities | 5,583 | |||
Asset retirement obligation and other | 2,418 | |||
|
| |||
Total liabilities assumed | 8,001 | |||
|
| |||
Net assets acquired | $ | 208,590 | ||
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ARP’s Carrizo Acquisition
On April 30, 2012, ARP completed the acquisition of certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash. The purchase price was funded through borrowings under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of the Partnership. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see Note 16).
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 12). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $1.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s consolidated balance sheet. All other costs associated with ARP’s acquisition of assets were expensed as incurred.
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The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):
Assets: | ||||
Natural gas and oil properties | $ | 190,946 | ||
Liabilities: | ||||
Asset retirement obligation | 3,903 | |||
|
| |||
Net assets acquired | $ | 187,043 | ||
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|
Due to the commingled nature of ARP’s acquisitions in the Fort Worth basin, it was impractical to provide separate financial information for each of ARP’s acquisitions subsequent to their respective dates of acquisition included within the Partnership’s consolidated combined statements of operations for the year ended December 31, 2012. Subsequent to their respective dates of acquisition and combined with the effect of ARP’s additional capital expenditures incurred, the DTE, Titan and Carrizo acquisitions had combined revenues of $32.1 million and net loss of $9.4 million for the year ended December 31, 2012.
APL’s Cardinal Acquisition
On December 20, 2012, APL completed the Cardinal Acquisition for $598.5 million in cash, including preliminary purchase price adjustments. The assets of these companies include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas. APL funded the purchase price for the Cardinal Acquisition in part from the private placement of $175.0 million of its 6.625% senior unsecured notes due 2020 (“6.625% APL Senior Notes”) at a premium of 3.0%, for net proceeds of $176.5 million (see Note 10); and from the sale of 10,507,033 APL common limited partner units in a public offering at a negotiated purchase price of $31.00 per unit, generating net proceeds of approximately $319.3 million, including the Partnership’s contribution of $6.7 million to maintain its 2.0% general partner interest in APL (see Note 16). APL funded the remaining purchase price from its senior secured revolving credit facility (see Note 10). In connection with the Cardinal Acquisition, APL placed $25.0 million of the purchase price into an escrow account, which was included within prepaid expenses and other with a corresponding amount in accrued liabilities on the Partnership’s consolidated balance sheet at December 31, 2012. The amounts in escrow related to certain closing conditions.
APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 12). In conjunction with the issuance of APL’s common limited partner units associated with the acquisition, APL recorded $12.2 million of transaction fees which were included in the $319.3 million net proceeds recorded to non-controlling interests on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate the facts and circumstances that existed as of the acquisition date.
The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their estimated fair values at the date of the acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands):
Assets: | ||||
Cash | $ | 3,246 | ||
Accounts receivable | 19,618 | |||
Prepaid expenses and other | 1,377 | |||
|
| |||
Total current assets | 24,241 | |||
Property, plant and equipment | 295,855 | |||
Intangible assets – contracts | 107,530 | |||
Goodwill | 310,904 | |||
|
| |||
Total assets acquired | $ | 738,530 | ||
|
| |||
Liabilities: | ||||
Current portion of long-term debt | 341 | |||
Accounts payable and accrued liabilities | 16,496 | |||
|
| |||
Total current liabilities | 16,837 | |||
Deferred tax liability, net | 30,082 | |||
Long-term debt, less current portion | 604 | |||
|
| |||
Total liabilities assumed | 47,523 | |||
Non-controlling interest | 89,310 | |||
|
| |||
Net assets acquired | 601,697 | |||
Less cash received | (3,246 | ) | ||
|
| |||
Net cash paid for acquisition | $ | 598,451 | ||
|
|
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The fair value of MarkWest’s 40% non-controlling interest in Centrahoma was determined based upon the purchase price allocated to the 60% controlling interest APL acquired.
Revenues and net income of $8.5 million and $1.0 million, respectively, have been included in the Partnership’s consolidated combined financial statements related to the Cardinal Acquisition for the year ended December 31, 2012.
The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the DTE, Cardinal, Titan and Carrizo acquisitions, including the borrowings under the respective revolving credit facilities, issuances of common and preferred units and net proceeds from APL’s 6.625% Senior Notes, had occurred on January 1, 2011. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the acquisitions had occurred on January 1, 2011 or the results that will be attained in future periods (in thousands, except per unit data; unaudited):
Years Ended December 31, | ||||||||
2012 | 2011 | |||||||
Total revenues and other | $ | 1,842,897 | $ | 1,933,768 | ||||
Income (loss) from continuing operations | (31,865 | ) | 76,567 | |||||
Net loss attributable to common limited partners | (54,938 | ) | (173,575 | ) | ||||
Net loss attributable to common limited partners per unit: | ||||||||
Basic | $ | (1.07 | ) | $ | (3.60 | ) | ||
Diluted | $ | (1.07 | ) | $ | (3.60 | ) |
ARP’s Equal Acquisition
In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. Both transactions were funded through borrowings under ARP’s revolving credit facility. As a result of ARP’s acquisition of Equal’s remaining interest in the undeveloped acres, the existing joint venture agreement between ARP and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system, is operated by ARP.
NOTE 5 – APL EQUITY METHOD INVESTMENTS
West Texas LPG Pipeline Limited Partnership
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 common-carrier pipeline system that transports NGLs 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. The Partnership recognizes APL’s 20% interest in West Texas LPG as an investment in joint venture on its consolidated balance sheets. At the acquisition date, the carrying value of the 20% interest in West Texas LPG exceeded APL’s share of the underlying net assets
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of West Texas LPG by approximately $49.9 million, which related to the fair value of the property, plant and equipment in excess of book value. This excess will be depreciated over approximately 38 years. 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. APL incurred costs of $0.6 million during year ended December 31, 2011, related to the acquisition of West Texas LPG, which are reported in general and administrative expenses on the Partnership’s consolidated statements of operations. During the year ended December 31, 2012 and 2011, APL recognized $6.3 million and $4.6 million, respectively, of equity income within other, net on the Partnership’s consolidated combined statements of operations related to APL’s West Texas LPG interest. APL’s equity method investments are subject to impairment evaluation. APL evaluated its investment in West Texas LPG as of December 31, 2012 and determined there was no impairment of the investment.
Laurel Mountain
On February 17, 2011, APL completed the sale of its 49% non-controlling interest in the Laurel Mountain joint venture to AEI (see Note 3). The Laurel Mountain joint venture was formed in May 2009 by APL and subsidiaries of the Williams Companies, Inc. (NYSE: WMB; “Williams”) to own and operate APL’s Appalachian Basin natural gas gathering system. APL used the proceeds from the sale to repay its indebtedness and for general corporate purposes. APL also retained its preferred distribution rights with respect to a remaining $8.5 million note receivable due from Williams, an investment grade rated entity, related to the formation of Laurel Mountain, including interest due on this note. APL accounted for its ownership of Laurel Mountain as an equity investment included within investment in joint venture on the Partnership’s consolidated balance sheet at fair value, based upon the value received for the 51% contributed to the Laurel Mountain joint venture during the year ended December 31, 2009. APL accounted for its ownership interest in the income of Laurel Mountain as other, net on the Partnership’s consolidated combined statements of operations. Since APL accounted for its ownership as an equity investment, it did not reclassify the earnings or the gain on sale related to Laurel Mountain to discontinued operations upon the sale of its ownership interest. The Partnership recognized a gain of $256.3 million and a loss of $2.2 million during the year ended December 31, 2011 and 2010, respectively, which are included in gain (loss) on asset sales and disposal within the Partnership’s consolidated combined statements of operations. The Partnership also reclassified the $8.5 million note receivable previously recorded to investment in joint venture to prepaid expenses and other on the Partnership’s consolidated balance sheets. In December 2011, Williams made a cash payment to APL to settle the remaining $8.5 million balance on the note receivable plus accrued interest of $0.2 million.
The following table summarizes the components of equity income within other, net on the Partnership’s consolidated combined statements of operations (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Equity income in Laurel Mountain | $ | — | $ | 462 | $ | 4,920 | ||||||
Equity income in WTLPG | 6,323 | 4,563 | — | |||||||||
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Equity income in joint ventures | $ | 6,323 | $ | 5,025 | $ | 4,920 | ||||||
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NOTE 6 – DISCONTINUED OPERATIONS
On September 16, 2010, APL completed the sale of its Elk City natural gas gathering systems and the related processing and treating facilities 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 10). 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 gain from sale of discontinued operations on its consolidated combined statement of operations for the year ended December 31, 2010.
The following table summarizes the components included within income (loss) from discontinued operations on the Partnership’s consolidated combined statements of operations (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Total revenues | $ | — | $ | — | $ | 129,908 | ||||||
Total costs and expenses | — | (81 | ) | (120,855 | ) | |||||||
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|
| |||||||
Income (loss) from discontinued operations | $ | — | $ | (81 | ) | $ | 9,053 | |||||
|
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|
|
| |||||||
Total income (loss) from discontinued operations | $ | — | $ | (81 | ) | $ | 9,053 | |||||
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NOTE 7 – PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at the dates indicated (in thousands):
December 31, | Estimated Useful Lives in Years | |||||||||||
2012 | 2011 | |||||||||||
Natural gas and oil properties: | ||||||||||||
Proved properties: | ||||||||||||
Leasehold interests | $ | 244,476 | $ | 61,587 | ||||||||
Pre-development costs | 1,935 | 2,540 | ||||||||||
Wells and related equipment | 1,222,475 | 828,780 | ||||||||||
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| |||||||||
Total proved properties | 1,468,886 | 892,907 | ||||||||||
Unproved properties | 292,053 | 43,253 | ||||||||||
Support equipment | 13,110 | 9,413 | ||||||||||
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| |||||||||
Total natural gas and oil properties | 1,774,049 | 945,573 | ||||||||||
Pipelines, processing and compression facilities | 2,326,186 | 1,646,320 | 2 – 40 | |||||||||
Rights of way | 179,018 | 161,275 | 20 – 40 | |||||||||
Land, buildings and improvements | 25,609 | 23,416 | 3 – 40 | |||||||||
Other | 26,656 | 22,734 | 3 – 10 | |||||||||
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| |||||||||
4,331,518 | 2,799,318 | |||||||||||
Less – accumulated depreciation, depletion and amortization | (828,909 | ) | (706,035 | ) | ||||||||
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| |||||||||
$ | 3,502,609 | $ | 2,093,283 | |||||||||
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During the year ended December 31, 2012, ARP recognized a $7.0 million loss on asset disposal pertaining to its decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 to not achieve due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and related properties and recorded a loss related to the net book values of those assets during the year ended December 31, 2012.
During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairment related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for ARP’s shallow natural gas wells in the Antrim and Niobrara Shales. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for ARP’s shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, ARP recognized $50.7 million of asset impairment related to gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for its shallow natural gas wells in Chattanooga and Upper Devonian Shales. These impairments related to the carrying amount of gas and oil properties being in excess of ARP’s estimate of their fair value at December 31, 2012, 2011 and 2010. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
NOTE 8 – OTHER ASSETS
The following is a summary of other assets at the dates indicated (in thousands):
December 31, | ||||||||
2012 | 2011 | |||||||
Deferred financing costs, net of accumulated amortization of $26,053 and $19,331 at December 31, 2012 and 2011, respectively | $ | 45,629 | $ | 23,426 | ||||
Investment in Lightfoot | 19,882 | 19,514 | ||||||
Security deposits | 2,390 | 4,584 | ||||||
Other | 3,101 | 673 | ||||||
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| |||||
$ | 71,002 | $ | 48,197 | |||||
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Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 10). Amortization expense of deferred finance costs was $6.7 million, $5.1 million and $10.6 million for the years ended December 31, 2012, 2011 and 2010, respectively, which is recorded within interest expense on the Partnership’s consolidated combined statements of operations. In April 2011, APL recognized $5.2 million of accelerated amortization of deferred financing costs associated with the retirement of its 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”) and partial redemption of its 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”), which was recorded within loss on early extinguishment of debt on the Partnership’s consolidated combined statements of operations. In March 2011, the Partnership recognized an additional $4.9 million of accelerated amortization of its deferred financing costs associated with the retirement of its $70.0 million credit facility, which was recorded within interest expense on the Partnership’s consolidated combined statements of operations. In September 2010, APL recorded $4.4 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 6), which was included within loss on early extinguishment of debt on the Partnership’s consolidated combined statement of operations. There was no accelerated amortization of deferred financing costs during the year ended December 31, 2012.
At December 31, 2012, the Partnership owns an approximate 12% interest in Lightfoot LP and an approximate 16% interest in Lightfoot GP, the general partner of Lightfoot LP, an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot LP 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 years ended December 31, 2012, 2011 and 2010, the Partnership recorded equity income of $1.5 million, $16.6 million, and $2.1 million, respectively, within other, net on the Partnership’s consolidated combined statements of operations. During the year ended December 31, 2011, the Partnership recognized a gain associated with its equity ownership interest in Lightfoot of $15.0 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. During the years ended December 31, 2012, 2011 and 2010 the Partnership received net cash distributions of $0.9 million, $16.2 and $0.7, respectively. The net cash distributions received in 2011 included $14.2 million, representing its share of the cash distribution made to investors by Lightfoot LP with proceeds from the IRP sale.
NOTE 9 – ASSET RETIREMENT OBLIGATIONS
ARP recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. ARP also recognized a liability for its 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 and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.
The estimated liability was based on ARP’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 was 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. ARP has no assets legally restricted for purposes of settling asset retirement obligations. Except for ARP’s gas and oil properties, the Partnership and its subsidiaries determined that there were no other material retirement obligations associated with tangible long-lived assets.
A reconciliation of ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Asset retirement obligations, beginning of year | $ | 45,779 | $ | 42,673 | $ | 36,599 | ||||||
Liabilities incurred | 16,568 | 713 | 472 | |||||||||
Liabilities settled | (546 | ) | (209 | ) | (373 | ) | ||||||
Accretion expense | 2,993 | 2,602 | 2,205 | |||||||||
Revisions | — | — | 3,770 | |||||||||
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| |||||||
Asset retirement obligations, end of year | $ | 64,794 | $ | 45,779 | $ | 42,673 | ||||||
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28
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 asset retirement obligations and other in the Partnership’s consolidated balance sheets. During the year ended December 31, 2012, ARP incurred $15.6 million of future plugging and abandonment costs related to the acquisitions it consummated during the period (see Note 4).
NOTE 10 – DEBT
Total debt consists of the following at the dates indicated (in thousands):
December 31, | ||||||||
2012 | 2011 | |||||||
Revolving credit facility | $ | 9,000 | $ | — | ||||
ARP revolving credit facility | 276,000 | — | ||||||
ARP term loan | 75,425 | — | ||||||
APL revolving credit facility | 293,000 | 142,000 | ||||||
APL 8.75 % Senior Notes – due 2018 | 370,184 | 370,983 | ||||||
APL 6.625 % Senior Notes – due 2020 | 505,231 | — | ||||||
APL capital leases | 11,503 | 11,157 | ||||||
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| |||||
Total debt | 1,540,343 | 524,140 | ||||||
Less current maturities | (10,835 | ) | (2,085 | ) | ||||
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Total long-term debt | $ | 1,529,508 | $ | 522,055 | ||||
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Partnership’s Credit Facility
In May 2012, the Partnership entered into a new credit facility with a syndicate of banks that matures in May 2016. The credit facility has maximum lender commitments of $50.0 million, and up to $5.0 million of the credit facility may be in the form of standby letters of credit. At December 31, 2012, $9.0 million was outstanding under the credit facility. The Partnership’s obligations under the credit facility are secured by substantially all of its assets, including its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility may be guaranteed by future subsidiaries. At the Partnership’s election, interest on borrowings under the credit facility is determined by either LIBOR plus an applicable margin of between 3.50% and 4.50% per annum or the base rate plus an applicable margin of between 2.50% and 3.50% per annum. The applicable margin will fluctuate based on the utilization of the facility. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the borrowing base, which is included within interest expense on the Partnership’s consolidated combined statement of operations. At December 31, 2012, the weighted average interest rate on outstanding credit facility borrowings was 3.7%.
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 commitment deficiency exists or a default under the credit agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of the Partnership’s assets.
The credit agreement also contains covenants that require the Partnership to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than 3.25 to 1.0 as of the last day of any fiscal quarter and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in the Partnership’s credit facility, its ratio of Total Funded Debt to EBITDA was 0.0 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 208.1 to 1.0 at December 31, 2012.
At December 31, 2012, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.
29
ARP’s Credit Facility and Term Loan
At December 31, 2012, ARP had a senior secured revolving credit facility with a syndicate of banks with a borrowing base of $410.0 million with $276.0 million outstanding as well as a term loan credit facility with borrowings of $75.4 million. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $0.6 million was outstanding at December 31, 2012. On December 20, 2012, in connection with the completion of the DTE acquisition, ARP entered into an amendment to its revolving credit facility and a new term loan credit facility. The amendment to ARP’s revolving credit facility:
• | increased the borrowing base from $310.0 million to $410.0 million; |
• | stated that borrowings under the revolving credit facility bear interest, at ARP’s election, are at either LIBOR plus an applicable margin between 2.00% and 3.25% per annum 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 between 1.00% and 2.25% per annum; |
• | revised the maturity date to be the earlier of March 22, 2016 or February 19, 2014 (the date that is 91 days before the May 19, 2014 maturity date of ARP’s term loan credit facility) if any portion of the term loan debt is outstanding on that date; and |
• | amended the financial covenants to require that ARP’s ratio of Total Funded Debt (as defined in the credit agreement) to four quarters of EBITDA (as defined in the credit agreement) not be greater than 4.25 to 1.0 as of the last day of fiscal quarters ending on or before June 30, 2013, 4.00 to 1.0 as of September 30, 2013 and December 31, 2013, and 3.75 to 1.0 as of the last day of fiscal quarters ending after that date. |
ARP’s $77.6 million term loan facility matures May 19, 2014, and contains terms substantially similar to its revolving credit facility except:
• | ARP’s obligations are secured by second lien mortgages on its oil and gas properties and security interest in substantially all of its assets, and guarantees by substantially all of its subsidiaries; |
• | borrowings bear interest, at ARP’s option, at either the prime rate plus 6.5% or LIBOR plus 7.5%; |
• | ARP will be required to prepay borrowings with 100% of the net proceeds from any senior notes offering, and 33% of the net proceeds from any equity offering; and |
• | requires ARP to maintain a ratio of Total Funded Debt to EBITDA 0.50 higher than that required under its revolving credit facility, a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0 as of the last day of any fiscal quarter, and a minimum asset coverage ratio (as defined in the credit agreement) of at least 1.5 to 1.0. |
ARP borrowed $179.8 million under its revolving credit facility and $77.6 million under its term loan facility to partially fund the DTE Acquisition (see Note 4).
The revolving credit agreement contains customary covenants that limit ARP’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 its assets. ARP was in compliance with these covenants as of December 31, 2012. The credit agreement also requires ARP 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 4.25 to 1.0 as of the last day of any fiscal quarter, 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. Based on the definitions contained in ARP’s credit facility, its ratio of current assets to current liabilities was 1.3 to 1.0, its ratio of Total Funded Debt to EBITDA was 2.9 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 39.1 to 1.0 at December 31, 2012.
At December 31, 2012, the weighted average interest rate on outstanding credit facility borrowings was 2.8%, and the weighted average interest rate on outstanding term loan borrowings was 7.9%. There were no outstanding borrowings at December 31, 2011.
APL Credit Facility
At December 31, 2012, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $293.0 million was outstanding. Borrowings under APL’s credit facility bear interest,
30
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 1.00%, 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 December 31, 2012 was 2.6%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at December 31, 2012. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet at December 31, 2012. At December 31, 2012, APL had $306.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. The Partnership has not guaranteed any of the obligations under APL’s senior secured revolving credit facility.
On May 31, 2012, APL entered into an amendment to its revolving credit facility agreement, which among other changes:
• | increased the revolving credit facility from $450.0 million to $600.0 million; |
• | extended the maturity date from December 22, 2015 to May 31, 2017; |
• | reduced the applicable margin used to determine interest rates by 0.50%; |
• | revised the negative covenants to (i) permit investments in joint ventures equal to the greater of 20.0% of “Consolidated Net Tangible Assets” (as defined in APL’s credit agreement) or $340.0 million, provided APL is in compliance with the financial covenants and has a Minimum Liquidity (as defined in the credit agreement) of at least $50.0 million, and (ii) increased the general investment basket to 5.0% of “Consolidated Net Tangible Assets”; |
• | revised the definition of “Consolidated EBITDA” (as defined in APL’s credit agreement), which is used to calculate financial covenant compliance, to permit APL to include estimated projected Consolidated EBITDA for the first 12 months following the commencement of commercial operations of a capital expansion project with a cost in excess of $20.0 million, net of actual Consolidated EBITDA attributable to such capital expansion project, provided, however, that the projected Consolidated EBITDA from any such projects, in the aggregate, may not be included to the extent such amounts exceed 15% of unadjusted Consolidated EBITDA; and |
• | provided for the option of additional revolving credit commitments of up to $200.0 million, upon request by APL. |
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 the West OK, West TX and Centrahoma joint ventures and their respective subsidiaries; 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 requirements that APL maintain certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) 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 December 31, 2012.
APL Senior Notes
At December 31, 2012, APL had $370.2 million principal amount outstanding of APL 8.75% Senior Notes and $505.2 million principal outstanding of 6.625% APL senior notes which are unsecured notes due on October 1, 2020 (collectively, the “APL Senior Notes”).
The APL 8.75% Senior Notes were presented combined with a net $4.4 million unamortized premium as of December 31, 2012. 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.
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The APL 6.625% Senior Notes were presented combined with a net $5.2 million unamortized premium as of December 31, 2012. Interest on the APL 6.625% Senior Notes is payable semi-annually in arrears on April 1 and October 1. The APL 6.625% Senior Notes are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.
In September 2012, APL issued $325.0 million of the APL 6.625% Senior Notes, at par, in a private placement transaction. APL received net proceeds of $318.9 million and utilized the proceeds to reduce the outstanding balance on its revolving credit facility.
In December 2012, APL issued $175.0 million of the APL 6.625% Senior Notes in a private placement transaction. The APL 6.625% Senior Notes were issued at a premium of 103.0% of the principal amount for a yield of 6.0%. APL received net proceeds of $176.5 million and utilized the proceeds to partially finance the Cardinal Acquisition.
In connection with the issuance of the APL 6.625% Senior Notes in September and December 2012, APL entered into registration rights agreements, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by September 23, 2013 in the case of the 6.625% Senior Notes issued in September, or by December 15, 2013, in the case of the 6.625% Senior Notes issued in December. If APL does not meet the aforementioned deadline, the APL 6.625% Senior Notes issued in December 2012 will be subject to additional interest, up to 1% per annum, until such time that APL causes the exchange offer to be consummated.
In April 2011, APL redeemed $7.2 million of the APL 8.75% Senior Notes, which were tendered upon our offer to purchase the APL 8.75% Senior Notes, at par. The sale of APL’s 49% non-controlling interest in Laurel Mountain on February 17, 2011 constituted an “asset sale” pursuant to the terms of the indenture of the APL 8.75% Senior Notes. As a result of the asset sale, APL offered to purchase any and all of the APL 8.75% Senior Notes. Subsequent to the redemption of the APL 8.75% Senior Notes, APL redeemed all of the APL 8.125% Senior Notes. The redemption price was determined in accordance with the indenture for the APL 8.125% Senior Notes, plus accrued and unpaid interest thereon to the redemption date. APL paid $293.7 million to redeem the $275.5 million principal plus $11.2 million premium and $7.0 million accrued interest. In addition, APL recorded $5.2 million related to accelerated amortization of deferred financing costs associated with the retirement of the APL 8.125% Senior Notes and a partial redemption of the APL 8.75% Senior Notes.
The APL 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 Senior Notes are junior in right of payment to APL’s secured debt, including its obligations under its revolving credit facility.
Indentures governing the APL Senior Notes 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 its assets. APL was in compliance with these covenants as of December 31, 2012.
APL Capital Leases
During the year ended December 31, 2012, APL recorded $2.8 million related to capital lease agreements, including $0.9 million as part of the Cardinal Acquisition (see Note 4), within property, plant and equipment and recorded an offsetting liability within long-term debt on the Partnership’s consolidated balance sheets. This amount was based upon the minimum payments required under the leases and the Partnership’s incremental borrowing rate.
During the year ended December 31, 2011, APL amended an operating lease for eight natural gas compressors to require a mandatory purchase of the equipment at the end of the lease term, thereby converting the agreement to a capital lease upon the effective date of the amendment. As a result, APL recorded an asset of $11.4 million within property, plant and equipment and recorded an offsetting liability within long term debt on the Partnership’s consolidated balance sheets. This amount was based on the minimum payments required under the lease and APL’s incremental borrowing rate.
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The following is a summary of the leased property under capital leases, which are included within property, plant and equipment (see Note 7) (in thousands):
December 31, | ||||||||
2012 | 2011 | |||||||
Pipelines, processing and compression facilities | $ | 15,457 | $ | 12,507 | ||||
Less – accumulated depreciation | (1,066 | ) | (199 | ) | ||||
|
|
|
| |||||
$ | 14,391 | $ | 12,308 | |||||
|
|
|
|
Depreciation expense for leased properties was $0.7 million, $0.2 million and $0.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Depreciation expense for leased properties is included within depreciation and amortization expense on the Partnership’s consolidated combined statements of operations.
As of December 31, 2012, future minimum lease payments related to APL’s capital leases are as follows (in thousands):
Capital Lease Minimum Payments | ||||
2013 | $ | 11,264 | ||
2014 | 435 | |||
2015 | 245 | |||
2016 | 6 | |||
2017 | — | |||
Thereafter | — | |||
|
| |||
Total minimum lease payments | 11,950 | |||
Less amounts representing interest | (447 | ) | ||
|
| |||
Present value of minimum lease payments | 11,503 | |||
Less current portion of capital lease obligations | (10,835 | ) | ||
|
| |||
Long-term capital lease obligations | $ | 668 | ||
|
|
The aggregate amount of the Partnership’s, ARP’s and APL’s debt maturities is as follows (in thousands):
Years Ended December 31: | ||||
2013 | $ | 10,835 | ||
2014 | 75,848 | |||
2015 | 240 | |||
2016 | 285,005 | |||
2017 | 293,000 | |||
Thereafter | 865,822 | |||
|
| |||
Total principle maturities | 1,530,750 | |||
Unamortized premiums | 9,593 | |||
|
| |||
Total debt | $ | 1,540,343 | ||
|
|
Cash payments for interest for the Partnership and its subsidiaries were $38.8 million, $33.0 million and $91.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.
NOTE 11 – DERIVATIVE INSTRUMENTS
ARP and APL use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. ARP and APL enter into financial instruments to hedge forecasted commodity 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 commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, ARP 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 put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.
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ARP and APL formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. ARP 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, ARP and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of ARP 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, ARP and APL recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income and reclassify the portion relating to ARP’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, ARP and APL recognize changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations as they occur.
ARP and APL enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options.
ARP and APL enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity 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 physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids contracts are based on an OPIS Mt. Belvieu index.
Derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated balance sheets of $51.3 million and $46.4 million at December 31, 2012 and 2011, respectively. Of the $9.7 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at December 31, 2012, if the fair values of the instruments remain at current market values, the Partnership will reclassify $5.1 million of gains to gas and oil production revenue on its consolidated combined statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $4.6 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.
Atlas Resource Partners
The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands):
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amount of Assets Presented in the Consolidated Balance Sheets | ||||||||||
Offsetting Derivative Assets | ||||||||||||
As of December 31, 2012 | ||||||||||||
Current portion of derivative assets | $ | 14,248 | $ | (1,974 | ) | $ | 12,274 | |||||
Long-term portion of derivative assets | 14,724 | (5,826 | ) | 8,898 | ||||||||
Long-term portion of derivative liabilities | 800 | (800 | ) | — | ||||||||
|
|
|
|
|
| |||||||
Total derivative assets | $ | 29,772 | $ | (8,600 | ) | $ | 21,172 | |||||
|
|
|
|
|
| |||||||
As of December 31, 2011 | ||||||||||||
Current portion of derivative assets | $ | 14,146 | $ | (345 | ) | $ | 13,801 | |||||
Long-term portion of derivative assets | 21,485 | (5,357 | ) | 16,128 | ||||||||
|
|
|
|
|
| |||||||
Total derivative assets | $ | 35,631 | $ | (5,702 | ) | $ | 29,929 | |||||
|
|
|
|
|
|
34
Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amount of Liabilities Presented in the Consolidated Balance Sheets | ||||||||||
Offsetting Derivative Liabilities | ||||||||||||
As of December 31, 2012 | ||||||||||||
Current portion of derivative assets | $ | (1,974 | ) | $ | 1,974 | $ | — | |||||
Long-term portion of derivative assets | (5,826 | ) | 5,826 | — | ||||||||
Long-term portion of derivative liabilities | (1,688 | ) | 800 | (888 | ) | |||||||
|
|
|
|
|
| |||||||
Total derivative liabilities | $ | (9,488 | ) | $ | 8,600 | $ | (888 | ) | ||||
|
|
|
|
|
| |||||||
As of December 31, 2011 | ||||||||||||
Current portion of derivative liabilities | $ | (345 | ) | $ | 345 | $ | — | |||||
Long-term portion of derivative liabilities | (5,357 | ) | 5,357 | — | ||||||||
|
|
|
|
|
| |||||||
Total derivative liabilities | $ | (5,702 | ) | $ | 5,702 | $ | — | |||||
|
|
|
|
|
|
The following table summarizes ARP’s gain or loss recognized in the Partnership’s consolidated combined statements of operations for effective derivative instruments for the periods indicated (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Gain (loss) recognized in accumulated OCI | $ | 10,921 | $ | 35,156 | $ | 16,542 | ||||||
Gain reclassified from accumulated OCI into income | $ | (19,281 | ) | $ | (10,541 | ) | $ | (27,364 | ) |
During 2012, ARP received approximately $4.5 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2016. In conjunction with the early termination of these derivatives, ARP entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ARP’s credit facility (see Note 10). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income and will be reclassified into the Partnership’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.
In March 2012, ARP entered into contracts which provided the option to enter into swap contracts (“swaptions”) up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 4). In connection with the swaption contracts, ARP paid premiums of $4.6 million, which represented the fair value of contracts on the date of the transaction and was initially recorded as a derivative asset on the Partnership’s consolidated balance sheet and was fully amortized as of June 30, 2012. For the year ended December 31, 2012, ARP recorded $4.6 million of amortization expense in other, net on the Partnership’s consolidated combined statements of operations related to the swaption contracts.
ARP recognized gains of $19.3 million, $10.5 million and $27.4 million for the years ended December 31, 2012, 2011 and 2010, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in ARP’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 years ended December 31, 2012, 2011 and 2010 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
35
At December 31, 2012, ARP had the following commodity derivatives:
Natural Gas Fixed Price Swaps
Production Period Ending December 31, | Volumes | Average Fixed Price | Fair Value Asset/(Liability) | |||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||
2013 | 22,729,700 | $ | 3.841 | $ | 6,646 | |||||||||||||
2014 | 19,233,000 | $ | 4.203 | 3,292 | ||||||||||||||
2015 | 13,434,500 | $ | 4.265 | 442 | ||||||||||||||
2016 | 12,866,300 | $ | 4.386 | (379 | ) | |||||||||||||
2017 | 6,480,000 | $ | 4.648 | 126 | ||||||||||||||
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| |||||||||||||||||
$ | 10,127 | |||||||||||||||||
|
| |||||||||||||||||
Natural Gas Costless Collars | ||||||||||||||||||
Production | Option Type | Volumes | Average Floor and Cap | Fair Value | ||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||
2013 | Puts purchased | 5,520,000 | $ | 4.395 | $ | 5,334 | ||||||||||||
2013 | Calls sold | 5,520,000 | $ | 5.443 | (210 | ) | ||||||||||||
2014 | Puts purchased | 3,840,000 | $ | 4.221 | 2,432 | |||||||||||||
2014 | Calls sold | 3,840,000 | $ | 5.120 | (813 | ) | ||||||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | 2,170 | |||||||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (1,187 | ) | ||||||||||||
|
| |||||||||||||||||
$ | 7,726 | |||||||||||||||||
|
| |||||||||||||||||
Natural Gas Put Options | ||||||||||||||||||
Production | Option Type | Volumes | Average Fixed Price | Fair Value | ||||||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||||||
2013 | Puts purchased | 3,180,000 | $ | 3.450 | $ | 767 | ||||||||||||
2014 | Puts purchased | 1,800,000 | $ | 3.800 | 683 | |||||||||||||
2015 | Puts purchased | 1,440,000 | $ | 4.000 | 676 | |||||||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.150 | 865 | |||||||||||||
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| |||||||||||||||||
$ | 2,991 | |||||||||||||||||
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| |||||||||||||||||
Natural Gas Liquids Fixed Price Swaps | ||||||||||||||||||
Production | Volumes | Average Fixed Price | Fair Value | |||||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||||
2013 | 57,000 | $ | 90.871 | $ | (134 | ) | ||||||||||||
2014 | 21,000 | $ | 90.554 | (43 | ) | |||||||||||||
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| |||||||||||||||||
$ | (177 | ) | ||||||||||||||||
|
|
36
Crude Oil Fixed Price Swaps | ||||||||||||||||
Production | Volumes | Average Fixed Price | Fair Value | |||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2013 | 242,850 | $ | 91.532 | (398 | ) | |||||||||||
2014 | 180,000 | $ | 91.579 | (104 | ) | |||||||||||
2015 | 165,000 | $ | 88.436 | (251 | ) | |||||||||||
2016 | 39,000 | $ | 86.120 | (76 | ) | |||||||||||
2017 | 36,000 | $ | 84.600 | (75 | ) | |||||||||||
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| |||||||||||||||
$ | (904 | ) | ||||||||||||||
|
| |||||||||||||||
Crude Oil Costless Collars | ||||||||||||||||
Production | Option Type | Volumes | Average Floor and Cap | Fair Value | ||||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||||
2013 | Puts purchased | 65,000 | $ | 90.000 | 352 | |||||||||||
2013 | Calls sold | 65,000 | $ | 116.513 | (83 | ) | ||||||||||
2014 | Puts purchased | 41,160 | $ | 84.169 | 336 | |||||||||||
2014 | Calls sold | 41,160 | $ | 113.308 | (190 | ) | ||||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | 299 | |||||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (193 | ) | ||||||||||
|
| |||||||||||||||
$ | 521 | |||||||||||||||
|
| |||||||||||||||
Total ARP net assets | $ | 20,284 | ||||||||||||||
|
|
(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. |
Prior to its merger with Chevron on February 17, 2011, AEI monetized 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. At December 31, 2012, remaining hedge monetization cash proceeds of $10.9 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents on the Partnership’s consolidated balance sheet, and ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated balance sheets as of December 31, 2012 and 2011.
In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At December 31, 2012, net unrealized derivative assets of $2.8 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.
The derivatives payable to the Drilling Partnerships related to both the hedge monetization proceeds and future natural gas production of the Drilling Partnerships at December 31, 2012 and 2011 were included in the Partnership’s consolidated balance sheets as follows (in thousands):
December 31, | ||||||||
2012 | 2011 | |||||||
Current portion of derivative payable to Drilling Partnerships: | ||||||||
Hedge monetization proceeds | $ | (10,748 | ) | $ | (20,900 | ) | ||
Hedge contracts covering future natural gas production | (545 | ) | — | |||||
Long-term portion of derivative payable to Drilling Partnerships: | ||||||||
Hedge monetization proceeds | (205 | ) | (15,272 | ) | ||||
Hedge contracts covering future natural gas production | (2,224 | ) | — | |||||
|
|
|
| |||||
$ | (13,722 | ) | $ | (36,172 | ) | |||
|
|
|
|
At December 31, 2012, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships will have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 10), ARP is required to utilize this secured hedge facility for future
37
commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.
Atlas Pipeline Partners
For the years ended December 31, 2012, 2011 and 2010, APL did not apply hedge accounting for derivatives. Changes in fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations. The change in fair value of commodity-based derivative instruments entered into prior to the discontinuation of hedge accounting was reclassified from within accumulated other comprehensive income on the Partnership’s consolidated balance sheets to gathering and processing revenue on the Partnership’s consolidated combined statements of operations at the time the originally hedged physical transactions affected earnings.
The following table summarizes APL’s gross fair values of its derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands):
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts of Assets Presented in the Consolidated Balance Sheets | ||||||||||
Offsetting of Derivative Assets | ||||||||||||
As of December 31, 2012 | ||||||||||||
Current portion of derivative assets | $ | 23,534 | $ | (457 | ) | $ | 23,077 | |||||
Long-term portion of derivative assets | 9,637 | (1,695 | ) | 7,942 | ||||||||
|
|
|
|
|
| |||||||
Total derivative assets | $ | 33,171 | $ | (2,152 | ) | $ | 31,019 | |||||
|
|
|
|
|
| |||||||
As of December 31, 2011 | ||||||||||||
Current portion of derivative assets | $ | 11,603 | $ | (9,958 | ) | $ | 1,645 | |||||
Long-term portion of derivative assets | 17,011 | (2,197 | ) | 14,814 | ||||||||
|
|
|
|
|
| |||||||
Total derivative assets | $ | 28,614 | $ | (12,155 | ) | $ | 16,459 | |||||
|
|
|
|
|
| |||||||
Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts of Liabilities Presented in the Consolidated Balance Sheets | ||||||||||
Offsetting of Derivative Liabilities | ||||||||||||
As of December 31, 2012 | ||||||||||||
Current portion of derivative liabilities | $ | (457 | ) | $ | 457 | $ | — | |||||
Long-term portion of derivative liabilities | (1,695 | ) | 1,695 | — | ||||||||
|
|
|
|
|
| |||||||
Total derivative liabilities | $ | (2,152 | ) | $ | 2,152 | $ | — | |||||
|
|
|
|
|
| |||||||
As of December 31, 2011 | ||||||||||||
Current portion of derivative liabilities | $ | (9,958 | ) | $ | 9,958 | $ | — | |||||
Long-term portion of derivative liabilities | (2,197 | ) | 2,197 | — | ||||||||
|
|
|
| |||||||||
Total derivative liabilities | $ | (12,155 | ) | $ | 12,155 | $ | — | |||||
|
|
|
|
|
|
38
As of December 31, 2012, APL had the following commodity derivatives:
Fixed Price Swaps
Production Period | Purchased/Sold | Commodity | Volumes(2) | Average Fixed Price | Fair Value(1) | |||||||||||
Natural Gas | ||||||||||||||||
2013 | Sold | Natural Gas | 1,200,000 | $ | 3.476 | $ | (51 | ) | ||||||||
2014 | Sold | Natural Gas | 5,400,000 | $ | 3.903 | (689 | ) | |||||||||
Natural Gas Liquids | ||||||||||||||||
2013 | Sold | Natural Gas Liquids | 54,936,000 | $ | 1.257 | 14,961 | ||||||||||
2014 | Sold | Natural Gas Liquids | 29,610,000 | $ | 1.313 | 1,286 | ||||||||||
2015 | Sold | Natural Gas Liquids | 2,520,000 | $ | 1.965 | 567 | ||||||||||
Crude Oil | ||||||||||||||||
2013 | Sold | Crude Oil | 345,000 | $ | 97.170 | 1,381 | ||||||||||
2014 | Sold | Crude Oil | 210,000 | $ | 92.076 | (27 | ) | |||||||||
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| |||||||||||||||
Total Fixed Price Swaps | $ | 17,428 | ||||||||||||||
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|
Options
Production Period | Purchased/ Sold | Type | Commodity | Volumes(2) | Average Strike | Fair Value(1) Asset | ||||||||||||
Natural Gas Liquids | ||||||||||||||||||
2013 | Purchased | Put | Natural Gas Liquids | 38,556,000 | $ | 1.943 | 6,269 | |||||||||||
Crude Oil | ||||||||||||||||||
2013 | Purchased | Put | Crude Oil | 282,000 | $ | 100.100 | 3,035 | |||||||||||
2014 | Purchased | Put | Crude Oil | 331,500 | $ | 95.741 | 4,287 | |||||||||||
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| |||||||||||||||||
Total Options | $ | 13,591 | ||||||||||||||||
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| |||||||||||||||||
Total APL net asset | $ | 31,019 | ||||||||||||||||
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(1) | See Note 12 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. |
The following tables summarize the gross effect of APL’s derivative instruments on the Partnership’s consolidated combined statement of operations for the periods indicated (in thousands):
Years Ended December 31, | ||||||||||||||
2012 | 2011 | 2010 | ||||||||||||
Loss Reclassified from Accumulated Other Comprehensive Loss into Income | ||||||||||||||
Contract Type | Location | |||||||||||||
Interest rate contracts(1) | Interest expense | $ | — | $ | — | $ | (2,242 | ) | ||||||
Commodity contracts(1) | Gathering and processing revenue | (4,390 | ) | (6,835 | ) | (15,570 | ) | |||||||
Commodity contracts(1) | Discontinued Operations | — | — | (20,154 | ) | |||||||||
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|
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| |||||||||
$ | (4,390 | ) | $ | (6,835 | ) | $ | (37,966 | ) | ||||||
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|
| |||||||||
Derivatives not designated as hedges | ||||||||||||||
Gain (loss) recognized in gain (loss) on mark-to-market derivatives: | ||||||||||||||
Interest rate contract—realized(1)(2) | $ | — | $ | — | $ | (604 | ) | |||||||
Interest rate contract—unrealized(1)(3) | — | — | 598 | |||||||||||
Commodity contract—realized(2) | 10,993 | (13,124 | ) | (5,890 | ) | |||||||||
Commodity contract—unrealized(3) | 20,947 | (7,329 | ) | (49 | ) | |||||||||
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|
|
|
| |||||||||
Gain (loss) on mark-to-market derivatives | 31,940 | (20,453 | ) | (5,945 | ) | |||||||||
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|
| |||||||||
Gain (loss) recognized in discontinued operations: | ||||||||||||||
Commodity contract—realized(2) | — | — | (101 | ) | ||||||||||
Commodity contract—unrealized(3) | — | — | 766 | |||||||||||
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| |||||||||
Discontinued operations | — | — | 665 | |||||||||||
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| |||||||||
$ | 31,940 | $ | (20,453 | ) | $ | (5,280 | ) | |||||||
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(1) | Hedges previously designated as cash flow hedges. |
(2) | Realized gain (loss) represents the gain (loss) incurred when the derivative contract expires and/or is cash settled. |
(3) | Unrealized gain (loss) represents the mark-to-market gain (loss) recognized on open derivative contracts, which have not yet been settled. |
39
The fair value of the derivatives included in the Partnership’s consolidated balance sheets was as follows (in thousands):
December 31, | ||||||||
2012 | 2011 | |||||||
Current portion of derivative asset | $ | 35,351 | $ | 15,447 | ||||
Long-term derivative asset | 16,840 | 30,941 | ||||||
Current portion of derivative liability | — | — | ||||||
Long-term derivative liability | (888 | ) | — | |||||
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|
|
| |||||
Total Partnership net asset | $ | 51,303 | $ | 46,388 | ||||
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NOTE 12 – FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership and its subsidiaries own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. 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 assumptions 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
ARP and APL use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 11). ARP and APL manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. ARP’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 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.
Valuations for APL’s NGL fixed price swaps are based on forward price curves provided by a third party, which is considered to be Level 3 inputs. The prices for propane, isobutene, normal butane and natural gasoline are adjusted based
40
upon the relationship between the prices for the product/locations quoted by the third party and the underlying product/locations utilized for the swap contracts, as determined by a regression model of the historical settlement prices for the different product/locations. The regression model is recalculated on a quarterly basis. This adjustment is an unobservable Level 3 input. The NGL fixed price swaps are over the counter instruments which are not actively traded in an open market. However, the prices for the underlying products and locations do have a direct correlation to the prices for the products and locations provided by the third party, which are based upon trading activity for the products and locations quoted. A change in the relationship between these prices would have a direct impact upon the unobservable adjustment utilized to calculate the fair value of the NGL fixed price swaps. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3. The NGL options are over the counter instruments that are not actively traded in an open market, thus APL utilizes the valuations provided by the financial institutions that provide the NGL options for trade. These valuations are tested for reasonableness through the use of an internal valuation model.
Information for ARP’s and APL’s assets and liabilities measured at fair value at December 31, 2012 and 2011 was as follows (in thousands):
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
As of December 31, 2012 | ||||||||||||||||
Derivative assets, gross | ||||||||||||||||
ARP Commodity swaps | $ | — | $ | 15,859 | $ | — | $ | 15,859 | ||||||||
ARP Commodity puts | — | 2,991 | — | 2,991 | ||||||||||||
ARP Commodity options | — | 10,923 | — | 10,923 | ||||||||||||
APL Commodity swaps | — | 2,007 | 17,573 | 19,580 | ||||||||||||
APL Commodity options | — | 7,322 | 6,269 | 13,591 | ||||||||||||
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|
|
|
|
|
|
| |||||||||
Total derivative assets, gross | — | 39,102 | 23,842 | 62,944 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Derivative liabilities, gross | ||||||||||||||||
ARP Commodity swaps | — | (6,813 | ) | — | (6,813 | ) | ||||||||||
ARP Commodity puts | — | — | — | — | ||||||||||||
ARP Commodity options | — | (2,676 | ) | — | (2,676 | ) | ||||||||||
APL Commodity swaps | — | (1,393 | ) | (759 | ) | (2,152 | ) | |||||||||
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|
|
|
|
|
| |||||||||
Total derivative liabilities, gross | — | (10,882 | ) | (759 | ) | (11,641 | ) | |||||||||
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|
|
|
|
|
|
| |||||||||
Total derivatives, fair value, net | $ | — | $ | 28,220 | $ | 23,083 | $ | 51,303 | ||||||||
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|
|
|
|
|
| |||||||||
As of December 31, 2011 | ||||||||||||||||
Derivative assets, gross | ||||||||||||||||
ARP Commodity swaps | $ | — | $ | 20,908 | $ | — | $ | 20,908 | ||||||||
ARP Commodity puts | — | — | — | — | ||||||||||||
ARP Commodity options | — | 14,723 | — | 14,723 | ||||||||||||
APL Commodity swaps | — | 1,270 | 1,836 | 3,106 | ||||||||||||
APL Commodity options | — | 7,229 | 18,279 | 25,508 | ||||||||||||
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|
|
|
|
|
|
| |||||||||
Total derivative assets, gross | — | 44,130 | 20,115 | 64,245 | ||||||||||||
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|
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|
|
|
|
| |||||||||
Derivative liabilities, gross | ||||||||||||||||
ARP Commodity swaps | — | — | — | — | ||||||||||||
ARP Commodity puts | — | — | — | — | ||||||||||||
ARP Commodity options | — | (5,702 | ) | — | (5,702 | ) | ||||||||||
APL Commodity swaps | — | (2,766 | ) | (3,569 | ) | (6,335 | ) | |||||||||
APL Commodity options | — | (5,820 | ) | — | (5,820 | ) | ||||||||||
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|
|
|
|
|
|
| |||||||||
Total derivative liabilities, gross | — | (14,288 | ) | (3,569 | ) | (17,857 | ) | |||||||||
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|
|
|
|
|
|
| |||||||||
Total derivatives, fair value, net | $ | — | $ | 29,842 | $ | 16,546 | $ | 46,388 | ||||||||
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|
|
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|
41
APL’s Level 3 fair value amounts 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 for the periods indicated (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(2) | 58,002 | — | 110,796 | 28,187 | 28,187 | |||||||||||||||
Cash settlements from unrealized gain (loss)(3)(4) | (41,118 | ) | 10,826 | (18,186 | ) | 2,398 | 13,224 | |||||||||||||
Net change in unrealized loss(3) | — | (10,769 | ) | — | (9,875 | ) | (20,644 | ) | ||||||||||||
Option premium recognition(4) | — | — | — | (2,431 | ) | (2,431 | ) | |||||||||||||
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|
|
|
|
|
|
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|
| |||||||||||
Balance — December 31, 2011 | 49,644 | $ | (1,733 | ) | 92,610 | $ | 18,279 | $ | 16,546 | |||||||||||
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|
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|
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| |||||||||||
New contracts(2) | 84,294 | — | — | — | — | |||||||||||||||
Cash settlements from unrealized gain (loss)(3)(4) | (46,872 | ) | (7,863 | ) | (54,054 | ) | (142 | ) | (8,005 | ) | ||||||||||
Net change in unrealized gain (loss)(3) | — | 26,410 | — | 923 | 27,333 | |||||||||||||||
Option premium recognition(4) | — | — | — | (12,791 | ) | (12,791 | ) | |||||||||||||
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|
|
|
|
|
|
|
|
| |||||||||||
Balance — December 31, 2012 | 87,066 | $ | 16,814 | 38,556 | $ | 6,269 | $ | 23,083 | ||||||||||||
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(1) | Volumes are stated in thousand gallons. |
(2) | Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade. |
(3) | Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations. |
(4) | Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration. |
The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at December 31, 2012 and 2011 (in thousands):
Gallons | Third Party Quotes(1) | Adjustments(2) | Total Amount | |||||||||||||
As of December 31, 2012 | ||||||||||||||||
Propane swaps | 69,678 | $ | 16,302 | $ | (552 | ) | $ | 15,750 | ||||||||
Isobutane swaps | 1,134 | (219 | ) | 187 | (32 | ) | ||||||||||
Normal butane swaps | 6,174 | (909 | ) | 242 | (667 | ) | ||||||||||
Natural gasoline swaps | 10,080 | 3,247 | (1,484 | ) | 1,763 | |||||||||||
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|
|
|
|
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|
| |||||||||
Total NGL swaps — December 31, 2012 | 87,066 | $ | 18,421 | $ | (1,607 | ) | $ | 16,814 | ||||||||
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|
|
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| |||||||||
As of December 31, 2011 | ||||||||||||||||
Ethane swaps | 6,678 | $ | 31 | $ | — | $ | 31 | |||||||||
Propane swaps | 29,358 | (1,322 | ) | — | (1,322 | ) | ||||||||||
Isobutane swaps | 2,646 | (1,590 | ) | 570 | (1,020 | ) | ||||||||||
Normal butane swaps | 6,804 | (1,074 | ) | 343 | (731 | ) | ||||||||||
Natural gasoline swaps | 4,158 | 1,824 | (515 | ) | 1,309 | |||||||||||
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|
|
|
|
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| |||||||||
Total NGL swaps — December 31, 2011 | 49,644 | $ | (2,131 | ) | $ | 398 | $ | (1,733 | ) | |||||||
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|
|
|
|
|
|
|
(1) | Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap. |
(2) | Based upon the price adjustment to the price provided by the third party to adjust for product and location differentials. The adjustment is calculated through a regression model comparing settlement prices of the different products and locations over a three year historical period. |
42
The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for APL’s NGL swaps for the periods indicated (in thousands):
Level 3 Fair Value Adjustments | Adjustment based upon Regression Coefficient | |||||||||||||||
Lower 95% | Upper 95% | Average Coefficient | ||||||||||||||
As of December 31, 2012 | ||||||||||||||||
Propane swaps | $ | (552 | ) | 1.1285 | 1.1376 | 1.1331 | ||||||||||
Isobutane swaps | 187 | 1.1285 | 1.1376 | 1.1331 | ||||||||||||
Normal butane swaps | 242 | 1.0370 | 1.0416 | 1.0393 | ||||||||||||
Natural gasoline swaps | (1,484 | ) | 0.9019 | 0.9169 | 0.9078 | |||||||||||
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| |||||||||||||||
Total NGL swaps — December 31, 2012 | $ | (1,607 | ) | |||||||||||||
|
| |||||||||||||||
As of December 31, 2011 | ||||||||||||||||
Isobutane swaps | $ | 570 | 1.1239 | 1.1333 | 1.1286 | |||||||||||
Normal butane swaps | 343 | 1.0311 | 1.0355 | 1.0333 | ||||||||||||
Natural gasoline swaps | (515 | ) | 0.9351 | 0.9426 | 0.9389 | |||||||||||
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| |||||||||||||||
Total NGL swaps — December 31, 2011 | $ | 398 | ||||||||||||||
|
|
APL had $7.8 million and $11.5 million of NGL linefill at December 31, 2012 and 2011, respectively, which was included within prepaid expenses and other on the Partnership’s consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price. APL’s NGL linefill is defined as a Level 3 asset and is valued using the same forward price curve utilized to value APL’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was a reduction of $0.4 million and $0.8 million as of December 31, 2012 and 2011, respectively.
The following table provides a summary of changes in fair value of APL’s NGL linefill for the years ended December 31, 2012 and 2011 (in thousands):
NGL Linefill | ||||||||
Gallons | Amount | |||||||
Balance — January 1, 2011 | 10,408 | $ | 10,622 | |||||
Net change in NGL linefill valuation(1) | — | 907 | ||||||
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|
|
| |||||
Balance — December 31, 2011 | 10,408 | $ | 11,529 | |||||
|
|
|
| |||||
Cash settlements(1) | (2,520 | ) | (2,698 | ) | ||||
Net change in NGL linefill valuation(1) | — | (2,111 | ) | |||||
Acquired NGL linefill(2) | 1,260 | 1,063 | ||||||
|
|
|
| |||||
Balance — December 31, 2012 | 9,148 | $ | 7,783 | |||||
|
|
|
|
(1) | Included within gathering and processing revenues on the Partnership’s consolidated combined statements of operations. |
(2) | NGL linefill acquired as part of the Cardinal Acquisition (see Note 4). |
Other Financial Instruments
The estimated fair value of the Partnership and its subsidiaries’ 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 and its subsidiaries could realize upon the sale or refinancing of such financial instruments.
The Partnership and its subsidiaries’ other current assets and liabilities on its consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of the Partnership and its subsidiaries’ debt at December 31, 2012 and 2011, which consist principally of APL’s Senior Notes and borrowings under ARP’s and APL’s revolving and term loan credit facilities, were $1,576.9 million and $537.3 million, respectively, compared with the carrying amounts of $1,540.3 million and $524.1 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximate their estimated fair value. The estimated fair value of the APL Senior Notes is based upon the market approach and calculated using the yield of the APL Senior Notes as provided by financial institutions and thus is categorized as a Level 3 value.
43
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
ARP estimates the fair value of its 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 ARP and estimated inflation rates (see Note 9). Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2012 and 2011 was as follows (in thousands):
Years Ended December 31, | ||||||||||||||||
2012 | 2011 | |||||||||||||||
Level 3 | Total | Level 3 | Total | |||||||||||||
Asset retirement obligations | $ | 16,568 | $ | 16,568 | $ | 713 | $ | 713 | ||||||||
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|
|
|
|
|
|
| |||||||||
Total | $ | 16,568 | $ | 16,568 | $ | 713 | $ | 713 | ||||||||
|
|
|
|
|
|
|
|
ARP and APL estimate the fair value of their long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the years ended December 31, 2012, 2011 and 2010, ARP recognized $9.5 million, $7.0 million and $50.7 million impairments of long-lived assets, which were defined as Level 3 fair value measurements (see Note 2 –Impairment of Long-Lived Assets).
During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo and reserves and associated assets from Titan and DTE, and APL completed the Cardinal acquisition. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 9). These inputs require significant judgments and estimates by ARP’s and APL’s management at the time of the valuation and are subject to change.
In February 2012, APL acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period (“Trigger Payments”). The fair value of the Trigger Payments recognized upon acquisition resulted in a $6.0 million current liability, which was recorded within accrued liabilities on the Partnership’s consolidated balance sheets and a $6.0 million long-term liability, which was recorded within asset retirement obligations and other on the Partnership’s consolidated balance sheets. Sufficient volumes were achieved in December 2012 and APL paid the first Trigger Payment of $6.0 million in January 2013. The initial recording of the transaction was based upon preliminary valuation assessments and is subject to change. The range of the undiscounted amounts APL could pay related to the Trigger Payments is between $6.0 million and $12.0 million.
NOTE 13 – INCOME TAXES
As part of the Cardinal Acquisition (see Note 4), APL acquired a taxable subsidiary. The components of the federal and state income tax expense of APL’s taxable subsidiary are summarized as follows:
Year Ended December 31, 2012 | ||||
Deferred expense: | ||||
Federal | $ | 158 | ||
State | 18 | |||
|
| |||
Total income tax expense | $ | 176 | ||
|
|
As of December 31, 2012, APL had non-current net deferred income tax liabilities of $30.3 million. The components of net deferred tax liabilities for the year ended December 31, 2012 consist of the following:
December 31, 2012 | ||||
Deferred tax assets: | ||||
Net operating loss tax carryforwards and alternative minimum tax credits | $ | 10,277 | ||
Deferred tax liabilities: | ||||
Excess of asset carrying value over tax basis | (40,535 | ) | ||
|
| |||
Net deferred tax liabilities | $ | (30,258 | ) | |
|
|
44
APL had net operating loss carry forwards for federal income tax purposes of approximately $26.3 million, which expire at various dates from 2029 and 2032. APL believes it more likely than not that the deferred tax asset will be fully utilized.
APL estimates approximately $290.6 million of goodwill recorded as a result of the Cardinal Acquisition to be deductible for tax purposes.
NOTE 14 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP 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. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.
Relationship between ARP and APL. In the Chattanooga Shale, a portion of the natural gas produced by ARP is gathered and processed by APL. For the years ended December 31, 2012, 2011 and 2010, $0.4 million, $0.3 million and $0.6 million of gathering fees paid by ARP to APL were eliminated in consolidation.
NOTE 15 — COMMITMENTS AND CONTINGENCIES
General Commitments
The Partnership leases office space and equipment under leases with varying expiration dates. Rental expense was $9.6 million, $7.3 million and $7.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):
Years Ended December 31, | ||||
2013 | $ | 6,144 | ||
2014 | 5,535 | |||
2015 | 5,326 | |||
2016 | 3,962 | |||
2017 | 2,074 | |||
Thereafter | 5,256 | |||
|
| |||
$ | 28,297 | |||
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ARP 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 ARP, as managing general partner. ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, the management of ARP believes that any liability incurred would not be material. Also, ARP has agreed to subordinate a portion of its share of net partnership revenues from the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to seven years, in accordance with the terms of the partnership agreements. For the years ended December 31, 2012, 2011 and 2010, $6.3 million, $4.0 million and $10.9 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.
The Partnership and its subsidiaries are party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.
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APL has certain long-term unconditional purchase obligations and commitments, primarily throughput contracts. These agreements provide for transportation services to be used in the ordinary course of APL’s operations. Transportation fees paid related to these contracts were $10.5 million, $10.3 million and $9.5 million for the years ended December 31, 2012, 2011 and 2010, respectively. The future fixed and determinable portion of APL’s obligations as of December 31, 2012 was as follows: 2013—$9.1 million; 2014 – $9.5 million; and 2015-2017 – $3.5 million per year.
As of December 31, 2012, ARP and APL are committed to expend approximately $135.1 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.
Legal Proceedings
A subsidiary of the Partnership entered into two agreements with the EPA, effective on September 25, 2012, to settle alleged violations in connection with a fire that occurred at a natural gas well and associated well pad site in Washington County, Pennsylvania in 2010. The EPA alleged non-compliance with the Clean Air Act, including with respect to the storage and handling of the natural gas condensate, as well as non-compliance with the Emergency Planning and Community Right-to-Know Act of 1986. The subsidiary agreed to a civil penalty of $84,506 under a consent agreement and agreed to upgrade its facility pursuant to an administrative settlement agreement.
On August 3, 2011, CNX Gas Company LLC filed a lawsuit in the United States District Court for the Eastern District of Tennessee at Knoxville styledCNX Gas Company LLC vs. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC, and Scott Boruff, No. 3:11-cv-00362. On April 16, 2012, Atlas Energy Tennessee, LLC, a subsidiary of the Partnership, was brought in to the lawsuit by way of Amended Complaint. On April 23, 2012, the Court dismissed Chevron Appalachia, LLC as a party on the grounds of lack of subject matter jurisdiction over that entity.
The lawsuit alleges that CNX entered into a Letter of Intent with Miller Energy for the purchase by CNX of certain leasehold interests containing oil and natural gas rights, representing around 30,000 acres in East Tennessee. The lawsuit also alleges that Miller Energy breached the Letter of Intent by refusing to close by the date provided and by allegedly entertaining offers from third parties for the same leasehold interests. Allegations of inducement of breach of contract and related claims are made by CNX against the remaining defendants, on the theory that these parties knew of the terms of the Letter of Intent and induced Miller Energy to breach the Letter of Intent. CNX is seeking $15.5 million in damages. The Partnership asserts that it acted in good faith and believes that the outcome of the litigation will be resolved in its favor.
The Partnership and its subsidiaries are also parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership and its subsidiaries believe 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 16 – ISSUANCES OF UNITS
The Partnership recognizes gains on ARP’s and APL’s equity transactions as credits to partners’ capital on its consolidated balance sheets rather than as income on its consolidated combined statements of operations. These gains represent the Partnership’s portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.
In February 2011, the Partnership 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 Note 3).
Atlas Resource Partners
Equity Offerings
In November and December 2012, in connection with entering into a purchase agreement to acquire certain producing wells and net acreage from DTE, ARP sold an aggregate of 7,898,210 of its common limited partner units in a public offering at a price of $23.01 per unit, yielding net proceeds of approximately $174.5 million. ARP utilized the net proceeds from the sale to repay a portion of the outstanding balance under its revolving credit facility and $2.2 million under its term loan credit facility. In connection with the issuance of ARP’s common units, we recorded an $18.2 million gain within partner’s capital and a corresponding decrease in non-controlling interests on our consolidated balance sheet at December 31, 2012.
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In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million ARP common units and 3.8 million newly-created convertible ARP Class B preferred units (which have an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 4). The preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution.
ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC by January 25, 2013 to register the resale of the ARP common units issued on the acquisition closing date and those issuable upon conversion of the preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. On September 19, 2012, ARP filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on October 2, 2012. In connection with the issuance of ARP’s common and preferred units, the Partnership recorded a $37.8 million gain within partner’s capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet at December 31, 2012.
In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain executives of the Partnership. The common units issued by ARP are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. On August 28, 2012, the registration statement was declared effective by the SEC. In connection with the private placement of ARP’s common units, the Partnership recorded a $10.6 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet at December 31, 2012.
ARP Common Unit Distribution
In February 2012, the board of directors of the Partnership’s general partner approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to the Partnership’s unitholders using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of these limited partner units represented approximately 20.0% of the common limited partner units outstanding (see Note 1).
Atlas Pipeline Partners
In December 2012, APL completed the sale of 10,507,033 APL common units in a public offering at an offering price of $31.00 per unit and received net proceeds of $319.3 million, including $6.7 million contributed by the Partnership to maintain its 2.0% general partner interest in APL. APL used the net proceeds from this offering to fund a portion of the Cardinal Acquisition. In connection with the issuance of APL common units, the Partnership recorded a $7.9 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet at December 31, 2012. In November 2012, APL entered into an agreement to issue $200.0 million of newly created Class D convertible preferred units in a private placement in order to finance a portion of the Cardinal Acquisition. Under the terms of the agreement, the private placement of the Class D convertible preferred units was nullified upon APL’s issuance of common units in excess of $150.0 million prior to the closing date of the Cardinal Acquisition. As a result of APL’s December 2012 issuance of $319.3 million common units, the private placement agreement terminated without the issuance of the Class D preferred units, and APL paid a commitment fee equal to 2.0%, or $4.0 million (see Note 4).
In November 2012, APL entered into an equity distribution program with Citigroup. Pursuant to this program, APL is authorized to, at its discretion, issue common units to investors through Citigroup at prevailing market prices, up to an aggregate value of $150.0 million. Citigroup is not required to sell any specific number or dollar amount of the common units, but will use its reasonable efforts, consistent with its normal trading and sales practices, to sell such units. APL intends
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to use the net proceeds from any such offering for general partnership purposes. During the year ended December 31, 2012, the Partnership issued 275,429 common units under the equity distribution program for net proceeds of $8.7 million, including $0.2 million in commission paid to Citigroup. APL also received a capital contribution from the Partnership of $0.2 million for it to maintain its 2.0% general partner interest in APL. The net proceeds from APL’s common unit offering were utilized for general partnership purposes.
In November 2010, APL redeemed 15,000 units of Class B Preferred Units for cash at the liquidation value of $1,000 per unit, or $15.0 million, plus $0.2 million accrued dividends, representing the quarterly dividend on the 15,000 Class B Preferred Units prior to its redemption. Subsequent to the redemption, APL had no Class B Preferred Units outstanding.
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”), for total proceeds of $8.0 million. The APL Class C Preferred Units received distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The record date for the determination of holders entitled to receive distributions was the same as the record date for determination of common unit holders entitled to receive quarterly distributions. APL had the right to redeem some or all of the APL Class C Preferred Units for an amount equal to the face value of the APL Class C Preferred Units being redeemed plus all accrued but unpaid dividends. On May 27, 2011, APL redeemed the 8,000 APL Class C Preferred units for cash, at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividends on the 8,000 APL Class C Preferred Units prior to APL’s redemption. Subsequent to the redemption, APL had no 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 lowered the warrant exercise price to $6.00 from $6.35 per unit. In connection with the amendments, the holders of the warrants exercised all of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. In November 2010, APL received a capital contribution from the Partnership as General Partner of $0.3 million for the Partnership to maintain its 2.0% general partner interest in APL. 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 and to fund the early termination of certain derivative agreements.
NOTE 17 – 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 December 31, 2012 were as follows (in thousands, except per unit amounts):
Date Cash Distribution Paid | For Quarter Ended | Cash Distribution per Common | Total Cash Distributions Paid | |||
November 16, 2010 | September 30, 2010 | $0.05 | $1,385 | |||
February 18, 2011 | December 31, 2010 | $0.07 | $1,948 | |||
May 20, 2011 | March 31, 2011 | $0.11 | $5,635 | |||
August 19, 2011 | June 30, 2011 | $0.22 | $11,276 | |||
November 18, 2011 | September 30, 2011 | $0.24 | $12,303 | |||
February 17, 2012 | December 31, 2011 | $0.24 | $12,307 | |||
May 18, 2012 | March 31, 2012 | $0.25 | $12,830 | |||
August 17, 2012 | June 30, 2012 | $0.25 | $12,831 | |||
November 19, 2012 | September 30, 2012 | $0.27 | $13,866 |
On January 24, 2013, the Partnership declared a cash distribution of $0.30 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $15.4 million distribution will be paid on February 19, 2013 to unitholders of record at the close of business on February 6, 2013.
ARP Cash Distributions. ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. If ARP’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels.
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Distributions declared by ARP from its formation through December 31, 2012 were as follows (in thousands, except per unit amounts):
Date Cash | For Quarter Ended | Cash Distribution per | Total Cash | Total Cash | Total Cash | |||||||||||||
(in thousands) | (in thousands) | (in thousands) | ||||||||||||||||
May 15, 2012 | March 31, 2012 | $ | 0.12 | (1) | $ | 3,144 | $ | — | $ | 64 | ||||||||
August 14, 2012 | June 30, 2012 | $ | 0.40 | $ | 12,891 | $ | — | $ | 263 | |||||||||
November 14, 2012 | September 30, 2012 | $ | 0.43 | $ | 15,510 | $ | 1,652 | $ | 350 |
(1) | Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date the Partnership’s exploration and production assets were transferred to ARP, to March 31, 2012. |
On January 24, 2013, ARP declared a cash distribution of $0.48 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $23.6 million distribution, including $0.6 million to the Partnership, as general partner, and $1.8 million to its preferred limited partners, will be paid on February 14, 2013 to unitholders of record at the close of business on February 6, 2013.
APL Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% 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 December 31, 2012 were as follows (in thousands, except per unit amounts):
Date Cash Distribution Paid | For Quarter Ended | APL Cash Distribution Partner Unit | Total APL Cash | Total APL Cash | ||||||||||
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, 2011 | $ | 0.40 | $ | 21,400 | $ | 439 | |||||||
August 12, 2011 | June 30, 2011 | $ | 0.47 | $ | 25,184 | $ | 967 | |||||||
November 14, 2011 | September 30, 2011 | $ | 0.54 | $ | 28,953 | $ | 1,844 | |||||||
February 14, 2012 | December 31, 2011 | $ | 0.55 | $ | 29,489 | $ | 2,031 | |||||||
May 15, 2012 | March 31, 2012 | $ | 0.56 | $ | 30,030 | $ | 2,217 | |||||||
August 14, 2012 | June 30, 2012 | $ | 0.56 | $ | 30,085 | $ | 2,221 | |||||||
November 14, 2012 | September 30, 2012 | $ | 0.57 | $ | 30,641 | $ | 2,409 |
On January 23, 2013, APL declared a cash distribution of $0.58 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $40.6 million distribution, including $3.1 million to the Partnership, as general partner, will be paid on February 14, 2013 to unitholders of record at the close of business on February 7, 2013.
NOTE 18 – 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
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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 General Partner’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 5,763,781 common limited partner units. At December 31 2012, the Partnership had 4,548,930 phantom units and unit options outstanding under the 2010 LTIP, with 1,189,736 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 will 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.
In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership’s general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):
• | cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity); |
• | accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the Partnership’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction; |
• | provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); |
• | terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and |
• | make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate. |
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 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 December 31, 2012, 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 December 31, 2012, there are 14,048 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at December 31, 2012 include DERs. During the years ended December 31, 2012 and 2011, the Partnership paid $2.0 million and $1.0 million, respectively, with respect to the 2010 LTIP DERs. There were no amounts paid with respect to the 2010 LTIP DERs for the year ended December 31, 2010.
The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||||||||
Outstanding, beginning of year | 1,838,164 | $ | 22.11 | — | $ | — | — | $ | — | |||||||||||||||
Granted | 133,080 | 29.95 | 1,891,539 | 22.11 | — | — | ||||||||||||||||||
Vested(1) | (19,677 | ) | 20.11 | — | — | — | — | |||||||||||||||||
Forfeited | (72,808 | ) | 20.65 | (53,375 | ) | 21.21 | — | — | ||||||||||||||||
ARP anti-dilution adjustment(2) | 165,468 | — | — | — | — | — | ||||||||||||||||||
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Outstanding, end of year(3) | 2,044,227 | $ | 20.90 | 1,838,164 | $ | 22.11 | — | $ | — | |||||||||||||||
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Non-cash compensation expense recognized (in thousands) |
| $ | 11,612 | $ | 8,060 | $ | — | |||||||||||||||||
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(1) | The aggregate intrinsic values of phantom unit awards vested during the year ended December 31, 2012 was $0.7 million. No phantom unit awards vested during the years ended December 31, 2011 and 2010. |
(2) | The number of 2010 phantom units was adjusted concurrently with the distribution of ARP common units. |
(3) | The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2012 was $71.0 million. |
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At December 31, 2012, the Partnership had approximately $24.0 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 December 31, 2012, 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. There are 10,196 unit options outstanding under the 2010 LTIP at December 31, 2012 that will vest within the following twelve months. For the year ended December 31, 2012, the Partnership received cash of $0.1 million from the exercise of options. No cash was received from the exercise of options for the years ended December 31, 2011 and 2010.
The following table sets forth the 2010 LTIP unit option activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||||||||
Outstanding, beginning of year | 2,304,300 | $ | 22.12 | — | $ | — | — | $ | — | |||||||||||||||
Granted | 77,167 | 27.55 | 2,384,300 | 22.12 | — | — | ||||||||||||||||||
Exercised(1) | (5,438 | ) | 18.44 | — | — | — | — | |||||||||||||||||
Forfeited | (79,119 | ) | 20.33 | (80,000 | ) | 22.23 | — | — | ||||||||||||||||
ARP anti-dilution adjustment(2) | 207,793 | — | — | — | — | — | ||||||||||||||||||
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Outstanding, end of year(3)(4) | 2,504,703 | $ | 20.51 | 2,304,300 | $ | 22.12 | — | $ | — | |||||||||||||||
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Options exercisable, end of year(5) | 3,398 | $ | 20.85 | — | $ | — | — | $ | — | |||||||||||||||
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Non-cash compensation expense recognized (in thousands) |
| $ | 5,966 | $ | 4,591 | $ | — | |||||||||||||||||
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(1) | The intrinsic value of options exercised during the year ended December 31, 2012 was $0.1 million. No options were exercised during the years ended December 31, 2011 and 2010. |
(2) | The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. |
(3) | The weighted average remaining contractual life for outstanding options at December 31, 2012 was 8.3 years. |
(4) | The options outstanding at December 31, 2012 had an aggregate intrinsic value of $35.6 million. |
(5) | The weighted average remaining contractual life for exercisable options at December 31, 2012 was 8.6 years. No options were exercisable at December 31, 2011 and 2010. |
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At December 31, 2012, the Partnership had approximately $11.9 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 periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Expected dividend yield | 3.7 | % | 1.6 | % | — | |||||||
Expected unit price volatility | 45.0 | % | 48.0 | % | — | |||||||
Risk-free interest rate | 1.4 | % | 2.7 | % | — | |||||||
Expected term (in years) | 6.84 | 6.87 | — | |||||||||
Fair value of unit options granted | $ | 8.08 | $ | 9.79 | — |
2006 Long-Term Incentive Plan
The Board of Directors 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 2,261,516 common limited partner units. At December 31, 2012, the Partnership had 980,698 phantom units and unit options outstanding under the 2006 LTIP, with 977,839 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.
2006 Phantom Units. Through December 31, 2012, phantom units granted to employees 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, and phantom units granted to non-employee directors will vest 25% per year 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 December 31, 2012, 15,111 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at December 31, 2012 include DERs. During the years ended December 31, 2012, 2011 and 2010, respectively, the Partnership paid $42,000, $20,000 and $7,000 with respect to 2006 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheet.
The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||||||||
Outstanding, beginning of year | 32,641 | $ | 15.99 | 27,294 | $ | 13.81 | 138,875 | $ | 23.72 | |||||||||||||||
Granted | 25,248 | 29.70 | 17,685 | 17.71 | 20,594 | 10.68 | ||||||||||||||||||
Vested (1) | (10,107 | ) | 20.26 | (12,338 | ) | 13.65 | (131,675 | ) | 23.70 | |||||||||||||||
Forfeited | — | — | — | — | (500 | ) | 32.28 | |||||||||||||||||
ARP anti-dilution adjustment(2) | 2,977 | — | — | — | — | — | ||||||||||||||||||
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Outstanding, end of year(3)(4) | 50,759 | $ | 21.02 | 32,641 | $ | 15.99 | 27,294 | $ | 13.81 | |||||||||||||||
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Non-cash compensation expense recognized (in thousands) |
| $ | 660 | $ | 422 | $ | 726 | |||||||||||||||||
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|
|
|
(1) | The intrinsic value for phantom unit awards vested during the years ended December 31, 2012, 2011 and 2010 was $0.3 million, $0.2 million, and $1.8 million, respectively. |
(2) | The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units. |
(3) | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2012 was $1.8 million. |
(4) | There were 44,234 units at December 31, 2012 classified under liabilities on the Partnership’s consolidated balance sheets of $0.7 million due to the option of the participants to settle in cash instead of units. No units were classified under accrued liabilities at December 31, 2011. The respective weighted average grant date fair value for these units is $23.25 as of December 31, 2012. |
At December 31, 2012, the Partnership had approximately $0.9 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 December 31, 2012, 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
52
a change of control of the Partnership, as defined in the 2006 LTIP. There are no unit options outstanding under the 2006 LTIP at December 31, 2012 that will vest within the following twelve months. For the years ended December 31, 2012 and 2011, the Partnership received cash of $0.2 million and $0.2 million, respectively, from the exercise of options. No options were exercised for the year ended December 31, 2010.
The following table sets forth the 2006 LTIP unit option activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||||||||
Outstanding, beginning of year | 903,614 | $ | 21.52 | 955,000 | $ | 20.54 | 955,000 | $ | 20.54 | |||||||||||||||
Granted | — | — | — | — | — | — | ||||||||||||||||||
Exercised(1) | (51,998 | ) | 3.03 | (51,386 | ) | 3.24 | — | — | ||||||||||||||||
Forfeited | — | — | — | — | — | — | ||||||||||||||||||
ARP anti-dilution adjustment(2) | 78,323 | — | — | — | — | — | ||||||||||||||||||
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|
|
|
|
|
|
|
|
|
| |||||||||||||
Outstanding, end of year(3)(4) | 929,939 | $ | 20.75 | 903,614 | $ | 21.52 | 955,000 | $ | 20.54 | |||||||||||||||
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| |||||||||||||
Options exercisable, end of year(4)(5) | 929,939 | $ | 20.75 | 903,614 | $ | 21.52 | 855,000 | $ | 22.56 | |||||||||||||||
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| |||||||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | — | $ | 28 | $ | 519 | |||||||||||||||||
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|
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(1) | The intrinsic values of options exercised during the years ended December 31, 2012 and 2011 were $1.5 million and $1.0 million, respectively. No options were exercised during the year ended December 31, 2010. |
(2) | The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units. |
(3) | The weighted average remaining contractual life for outstanding options at December 31, 2012 was 3.9 years. |
(4) | The aggregate intrinsic value of options outstanding and exercisable at December 31, 2012 was approximately $13.0 million. |
(5) | The weighted average remaining contractual life for exercisable options at December 31, 2012 was 3.9 years. |
At December 31, 2012, 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 years ended December 31, 2012, 2011 and 2010 under the 2006 Plan.
The transfer of assets to ARP on March 5, 2012 and the subsequent distribution of ARP common units on March 13, 2012 resulted in an adjustment to the Partnership’s 2010 and 2006 long-term incentive plans. Concurrent with the distribution of ARP common units, the number of phantom units, restricted units and options in the plans were increased in an amount equivalent to the percentage change in the Partnership’s publicly traded unit price from the closing price on March 13, 2012 to the opening price on March 14, 2012. In addition, the strike price of unit option awards was decreased by the same percentage change.
ARP Long-Term Incentive Plan
ARP has a 2012 Long-Term Incentive Plan effective March 2012 (the “ARP LTIP”). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP GP (collectively, the “Participants”) under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. Up to 2,900,000 common units of ARP, subject to adjustment as provided for under the ARP LTIP, may be issued pursuant to awards granted under the ARP LTIP. The ARP LTIP is administered by the Compensation Committee of the board (the “ARP LTIP Committee”). At December 31, 2012, ARP had 2,463,976 phantom units, restricted units and unit options outstanding under the ARP LTIP, with 436,024 phantom units, restricted units and unit options available for grant.
Upon a change in control, as defined in the ARP LTIP, all unvested awards held by directors will 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 ARP 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.
53
In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):
• | cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity); |
• | accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction; |
• | provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); |
• | terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and |
• | make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate. |
ARP Phantom Units. Through December 31, 2012, phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the next four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at December 31, 2012, 213,368 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at December 31, 2012 include DERs. During the year ended December 31 2012, ARP paid $0.7 million with respect to ARP LTIP’s DERs. No amounts were paid during the years ended December 31, 2011 and 2010, respectively, with respect to DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheet.
The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||||||||
Outstanding, beginning of year | — | $ | — | — | $ | — | — | $ | — | |||||||||||||||
Granted | 949,476 | 24.76 | — | — | — | — | ||||||||||||||||||
Vested (1) | — | — | — | — | — | — | ||||||||||||||||||
Forfeited | (1,000 | ) | 24.67 | — | — | — | — | |||||||||||||||||
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|
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|
|
|
| |||||||||||||
Outstanding, end of year(2)(3) | 948,476 | $ | 24.76 | — | $ | — | — | $ | — | |||||||||||||||
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|
|
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|
| |||||||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 7,630 | $ | — | $ | — | |||||||||||||||||
|
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|
|
|
(1) | No phantom unit awards vested during the years ended December 31, 2012, 2011 and 2010. |
(2) | The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2012 was $21.3 million. |
(3) | There was $31,000 classified within liabilities on the Partnership’s consolidated balance sheets at December 31, 2012, representing 3,476 units, due to the option of the participants to settle in cash instead of units. No amounts were classified within liabilities on the Partnership’s consolidated balance sheet at December 31, 2011. The respective weighted average grant date fair value for these units was $28.75 at December 31, 2012. |
At December 31, 2012, ARP had approximately $5.9 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards.
54
ARP Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Through December 31, 2012, unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 378,875 unit options outstanding under the ARP LTIP at December 31, 2012 that will vest within the following twelve months. No cash was received from the exercise of options for the years ended December 31, 2012, 2011 and 2010.
The following table sets forth the ARP LTIP unit option activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||||||||
Outstanding, beginning of year | — | $ | — | — | $ | — | — | $ | — | |||||||||||||||
Granted | 1,517,500 | 24.68 | — | — | — | — | ||||||||||||||||||
Exercised(1) | — | — | — | — | — | — | ||||||||||||||||||
Forfeited | (2,000 | ) | 24.67 | — | — | — | — | |||||||||||||||||
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|
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|
|
|
|
|
|
|
|
| |||||||||||||
Outstanding, end of year(2)(3) | 1,515,500 | $ | 24.68 | — | $ | — | — | $ | — | |||||||||||||||
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|
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|
|
|
|
|
|
|
| |||||||||||||
Options exercisable, end of year(4) | — | $ | — | — | $ | — | — | $ | — | |||||||||||||||
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|
|
|
|
| |||||||||||||
Non-cash compensation expense recognized (in thousands) | $ | 3,198 | $ | — | $ | — | ||||||||||||||||||
|
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|
|
|
(1) | No options were exercised during the years ended December 31, 2012, 2011 and 2010. |
(2) | The weighted average remaining contractual life for outstanding options at December 31, 2012 was 9.4 years. |
(3) | There was no aggregate intrinsic value of options outstanding at December 31, 2012. |
(4) | No options were exercisable at December 31, 2012. |
At December 31 2012, ARP had approximately $6.0 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. ARP 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 periods indicated:
Year Ended December 31, 2012 | ||||
Expected dividend yield | 5.9 | % | ||
Expected unit price volatility | 47.0 | % | ||
Risk-free interest rate | 1.0 | % | ||
Expected term (in years) | 6.25 | |||
Fair value of unit options granted | $ | 6.10 |
APL Long-Term Incentive Plans
APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011 (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, 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. The APL LTIPs are administered by APL’s compensation committee (the “APL LTIP Committee”). 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 December 31, 2012, APL had 1,053,242 phantom units outstanding under the APL LTIPs, with 1,524,317 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options, which have vested and have been exercised. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the consolidated combined financial statements based upon their current fair market value.
55
APL Phantom Units. Through December 31, 2012, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the APL 2010 LTIP, the holders of 300,000 of the 375,000 equity indexed bonus units (“APL Bonus Units”) under APL’s subsidiary’s plan discussed below 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. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of APL’s board automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at December 31, 2012, 291,359 units will vest within the following twelve months. On February 17, 2011, the employment agreement with APL’s 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 December 31, 2012 include DERs. The amounts paid with respect to APL LTIP DERs were $2.0 million, $0.8 million and $0.2 million, respectively, for the years ended December 31, 2012, 2011 and 2010. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheet.
The following table sets forth the APL LTIP phantom unit activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||||||||
Outstanding, beginning of year | 394,489 | $ | 21.63 | 490,886 | $ | 11.75 | 52,233 | $ | 39.72 | |||||||||||||||
Granted | 907,637 | 34.94 | 178,318 | 33.47 | 575,112 | 10.49 | ||||||||||||||||||
Vested and issued(1)(2) | (181,209 | ) | 17.88 | (233,465 | ) | 11.34 | (126,584 | ) | 17.11 | |||||||||||||||
Forfeited | (67,675 | ) | 29.83 | (41,250 | ) | 13.49 | (9,875 | ) | 17.39 | |||||||||||||||
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|
|
|
|
|
| |||||||||||||
Outstanding, end of year(3)(4) | 1,053,242 | $ | 33.21 | 394,489 | $ | 21.63 | 490,886 | $ | 11.75 | |||||||||||||||
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| |||||||||||||
Non-cash compensation expense recognized (in thousands)(5) | $ | 11,635 | $ | 3,271 | $ | 3,480 | ||||||||||||||||||
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|
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(1) | The intrinsic values for phantom unit awards vested and issued during the years ended December 31, 2012, 2011 and 2010 were $5.5 million, $7.4 million and $1.5 million, respectively. |
(2) | There were 792 and 414 matured phantom units, which were settled for $26,000 and $14,000 cash during the years ended December 31, 2012 and 2011, respectively. No phantom units were cash settled during the year ended December 31, 2010. |
(3) | There were 17,926 and 14,675 outstanding phantom unit awards at December 31, 2012 and 2011, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards. |
(4) | The aggregate intrinsic values for phantom unit awards outstanding at December 31, 2012 and 2011 were $33.3 million and $14.7 million, respectively. |
(5) | Non-cash compensation expense for the year ended December 31, 2011 includes incremental compensation expense of $0.5 million, related to the accelerated vesting of phantom units held by APL’s CEO. Non-cash compensation expense for the year ended December 31, 2010 includes $2.2 million related to Bonus Units converted to phantom units. |
At December 31, 2012, APL had approximately $23.2 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.2 years.
APL Unit Options. At December 31, 2012, there were no unit options outstanding. On February 17, 2011, the employment agreement with the CEO of APL’s General Partner was terminated in connection with the Chevron Merger (see Note 3) and 50,000 outstanding unit options held by the CEO automatically vested. As of December 31, 2012, all unit options had been exercised.
56
The following table sets forth the APL LTIPs’ unit option activity for the periods indicated:
Years Ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||||||||
Outstanding, beginning of year | — | $ | — | 75,000 | $ | 6.24 | 100,000 | $ | 6.24 | |||||||||||||||
Exercised(1) | — | — | (75,000 | ) | 6.24 | (25,000 | ) | 6.24 | ||||||||||||||||
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|
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| |||||||||||||
Outstanding, end of year(2) | — | $ | — | — | $ | — | 75,000 | $ | 6.24 | |||||||||||||||
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Non-cash compensation expense recognized (in thousands)(3) | $ | — | $ | 3 | $ | 4 | ||||||||||||||||||
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(1) | The intrinsic values for the options exercised during the year ended December 31, 2011 and 2010, were $1.7 million and $0.5 million, respectively. Approximately $0.5 million and $0.2 million were received from the exercise of unit option awards during the year ended December 31, 2011 and 2010, respectively. |
(2) | No options are outstanding or exercisable at December 31, 2012. |
(3) | Incremental expense of $2,000, related to the accelerated vesting of options held by APL’s CEO, was recognized during the year ended December 31, 2011. |
At December 31, 2012, 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 years ended December 31, 2012, 2011 and 2010 under the APL LTIPs.
APL Employee Incentive Compensation Plan and Agreement
A wholly-owned subsidiary of APL has an incentive plan (the “Cash Plan”), which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”). The Cash Plan is administered by a committee appointed by the CEO of APL’s General Partner. Under the Cash Plan, cash bonus units may be awarded to Participants at the discretion of the committee. An APL Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of a common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause.
At December 31, 2012, APL had no outstanding APL Bonus Units under the Cash Plan and does not anticipate any further grants under the Cash Plan. APL recognized compensation expense related to these awards based upon the fair value, which is re-measured each reporting period based upon the current fair value of the underlying common units. During the years ended December 31, 2012 and 2011, 25,500 APL Bonus Units and 24,750 APL Bonus Units, respectively, vested and cash payments were made for $0.7 million and $0.9 million, respectively. APL recognized income of $0.1 million and $0.2 million during the years ended December 31, 2012 and 2010, respectively, and expense of $0.9 million during the year ended December 31, 2011, which was recorded within general and administrative expense on the Partnership’s consolidated combined statements of operations. APL had $0.8 million at December 31, 2011, included within accrued liabilities on the Partnership’s consolidated balance sheet with regard to these awards, which represented their fair value as of that date.
57
NOTE 19 – OPERATING SEGMENT INFORMATION
The Partnership’s operations include three reportable operating segments (see Note 2). These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Atlas Resource: | ||||||||||||
Revenues | $ | 267,629 | $ | 247,522 | $ | 344,678 | ||||||
Operating costs and expenses | (245,832 | ) | (189,511 | ) | (228,994 | ) | ||||||
Depreciation, depletion and amortization expense | (52,582 | ) | (31,938 | ) | (40,758 | ) | ||||||
Asset impairment | (9,507 | ) | (6,995 | ) | (50,669 | ) | ||||||
Gain (loss) on asset sales and disposal | (6,980 | ) | 87 | (2,947 | ) | |||||||
Interest expense | (4,195 | ) | — | — | ||||||||
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|
|
| |||||||
Segment income (loss) | $ | (51,467 | ) | $ | 19,165 | $ | 21,310 | |||||
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|
|
| |||||||
Atlas Pipeline: | ||||||||||||
Revenues | $ | 1,236,819 | $ | 1,306,450 | $ | 939,889 | ||||||
Operating costs and expenses | (1,037,406 | ) | (1,138,898 | ) | (803,967 | ) | ||||||
Depreciation, depletion and amortization expense | (90,029 | ) | (77,435 | )�� | (74,897 | ) | ||||||
Gain (loss) on asset sales and disposal | — | 256,202 | (10,729 | ) | ||||||||
Interest expense | (41,760 | ) | (31,603 | ) | (87,273 | ) | ||||||
Loss on extinguishment of debt | — | (19,574 | ) | (4,359 | ) | |||||||
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|
|
|
|
| |||||||
Segment income (loss) | $ | 67,624 | $ | 295,142 | $ | (41,336 | ) | |||||
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|
|
|
| |||||||
Corporate and other: | ||||||||||||
Revenues | $ | 1,575 | $ | 16,602 | $ | 2,097 | ||||||
Operating costs and expenses | (34,048 | ) | (16,694 | ) | (3,540 | ) | ||||||
Depreciation, depletion and amortization expense | — | — | — | |||||||||
Gain (loss) on asset sales and disposal | — | 3 | — | |||||||||
Interest expense | (565 | ) | (6,791 | ) | (3,175 | ) | ||||||
|
|
|
|
|
| |||||||
Segment loss | $ | (33,038 | ) | $ | (6,880 | ) | $ | (4,618 | ) | |||
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|
|
|
|
| |||||||
Reconciliation of segment income (loss) to net income (loss) from continuing operations: | ||||||||||||
Segment income (loss): | ||||||||||||
Atlas Resource | $ | (51,467 | ) | $ | 19,165 | $ | 21,310 | |||||
Atlas Pipeline | 67,624 | 295,142 | (41,336 | ) | ||||||||
Corporate and other | (33,038 | ) | (6,880 | ) | (4,618 | ) | ||||||
|
|
|
|
|
| |||||||
Net income (loss) from continuing operations | (16,881 | ) | 307,427 | (24,644 | ) | |||||||
|
|
|
|
|
| |||||||
Capital expenditures: | ||||||||||||
Atlas Resource | $ | 127,226 | $ | 47,324 | $ | 93,608 | ||||||
Atlas Pipeline | 373,533 | 245,426 | 45,752 | |||||||||
Corporate and other | — | — | — | |||||||||
|
|
|
|
|
| |||||||
Total capital expenditures | $ | 500,759 | $ | 292,750 | $ | 139,360 | ||||||
|
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|
|
|
|
December 31, | December 31, | |||||||
2012 | 2011 | |||||||
Balance sheet: | ||||||||
Goodwill: | ||||||||
Atlas Resource | $ | 31,784 | $ | 31,784 | ||||
Atlas Pipeline | 319,285 | — | ||||||
Corporate and other | — | — | ||||||
|
|
|
| |||||
$ | 351,069 | $ | 31,784 | |||||
|
|
|
| |||||
Total assets: | ||||||||
Atlas Resource | $ | 1,498,952 | $ | 702,366 | ||||
Atlas Pipeline | 3,065,638 | 1,930,812 | ||||||
Corporate and other | 32,604 | 51,593 | ||||||
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|
|
| |||||
$ | 4,597,194 | $ | 2,684,771 | |||||
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|
|
NOTE 20 – SUBSEQUENT EVENTS
Cash Distribution. On January 24, 2013, the Partnership declared a cash distribution of $0.30 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $15.4 million distribution was paid on February 19, 2013 to unitholders of record at the close of business on February 6, 2013.
58
Atlas Pipeline
Senior Notes. On February 11, 2013, APL issued $650.0 million of 5.875% unsecured Senior Notes due 2023 (“5.875% APL Senior Notes”) in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.8 million and plans to utilize the proceeds to redeem any or all of its outstanding 8.75% APL Senior Notes and repay a portion of its outstanding indebtedness under its revolving credit facility. APL has agreed to file a registration statement with respect to the 5.875% Senior Notes. On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding $365.8 million 8.75% APL Senior Notes, excluding unamortized premium, and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes. Approximately $268.4 million aggregate principal amount of the 8.75% Senior Notes (representing approximately 73.4% of the outstanding 8.75% APL Senior Notes) were validly tendered as of the expiration date of the consent solicitation. APL estimates $5.4 million of accelerated amortization of deferred financing costs associated with the retirement of debt to be recorded in 2013, related to the retirement of the 8.75% APL Senior Notes. On February 11, 2013, APL accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent solicitation and entered into a supplemental indenture amending and supplementing the 8.75% Senior Note Indenture. APL also issued a notice to redeem all the 8.75% APL Senior Notes not purchased in connection with the tender offer. APL plans to fund the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes.
Cash Distribution. On January 23, 2013, APL declared a cash distribution of $0.58 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $40.6 million distribution, including $3.1 million to the Partnership, as general partner, was paid on February 14, 2013 to unitholders of record at the close of business on February 7, 2013.
Acquisition of Gas Gathering Systems and Related Assets. On January 7, 2013, APL paid $6.0 million for the first of two Trigger Payments related to the acquisition of a gas gathering system and related assets in February 2012. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts subject to delivery of certain minimum volumes of natural gas from a specified area within certain specified time periods. Sufficient volumes were achieved in December 2012 to meet the required minimum volumes for the first Trigger Payment.
Atlas Resource
Cash Distribution. On January 24, 2013, ARP declared a cash distribution of $0.48 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $23.6 million distribution, including $0.6 million to the Partnership, as general partner, and $1.8 million to its preferred limited partners, was paid on February 14, 2013 to unitholders of record at the close of business on February 6, 2013.
Senior Notes.On January 23, 2013, ARP issued $275.0 million of 7.75% senior unsecured notes due on January 15, 2021 (“7.75% ARP Senior Notes”). ARP used the net proceeds of approximately $268.3 million, net of underwriting fees and other offering costs of $6.7 million, to repay all of the indebtedness and accrued interest outstanding under its term loan credit facility and a portion of that outstanding under its revolving credit facility (see Note 10). Under the terms of ARP’s revolving credit facility, the borrowing base was reduced by 15% of the 7.75% ARP Senior Notes to $368.8 million. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $2.2 million of amortization expense related to deferred financing costs in January 2013. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if ARP does not reinvest the net proceeds within 18 months. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a “make whole” redemption price as defined in the indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. The indenture governing the 7.75% ARP Senior Notes contains covenants, including limitations of ARP’s ability to incur certain liens, 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 ARP’s assets.
NOTE 21 – SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserve Information. The preparation of ARP’s natural gas and oil reserve estimates was completed in accordance with its prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for ARP’s annual report on Form 10-K for the year ended
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December 31, 2012. For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located throughout the United States, primarily in Ohio, Oklahoma, Pennsylvania and Texas. The independent reserves engineer’s evaluation was based on more than 36 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The Partnership’s and ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 14 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by ARP’s senior engineering staff and management, with final approval by ARP’s Senior Vice President.
The reserve disclosures that follow reflect ARP’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil and gas reserves are those quantities of oil and gas, that by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows as of December 31, 2012, 2011 and 2010 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2012, 2011 and 2010, including adjustments related to regional price differentials and energy content.
There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within ARP or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.
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Reserve quantity information and a reconciliation of changes in proved reserve quantities included within ARP are as follows (unaudited):
Gas (Mcf) | Oil (Bbls) (1) | NGLs (Bbls) (1) | ||||||||||
Balance, January 1, 2010 | 183,654,964 | 1,822,722 | — | |||||||||
Extensions, discoveries and other additions(2) | 64,776,600 | — | — | |||||||||
Sales of reserves in-place | (9,241,358 | ) | — | — | ||||||||
Purchase of reserves in-place | 366,276 | 1,203 | — | |||||||||
Transfers to limited partnerships | (8,824,000 | ) | — | — | ||||||||
Revisions(3) | (41,580,400 | ) | 326,913 | — | ||||||||
Production | (13,087,079 | ) | (318,303 | ) | — | |||||||
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Balance, December 31, 2010 | 176,065,003 | 1,832,535 | — | |||||||||
Extensions, discoveries and other additions(2) | 9,966,952 | 8,217 | — | |||||||||
Sales of reserves in-place | (990 | ) | — | — | ||||||||
Purchase of reserves in-place | 586,662 | 2,216 | — | |||||||||
Transfers to limited partnerships | (6,042,432 | ) | — | — | ||||||||
Revisions(4) | (11,436,615 | ) | 77,661 | — | ||||||||
Production | (11,462,149 | ) | (274,330 | ) | — | |||||||
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Balance, December 31, 2011 | 157,676,431 | 1,646,299 | — | |||||||||
Extensions, discoveries and other additions(2) | 6,756,817 | 10,688 | — | |||||||||
Sales of reserves in-place | — | — | — | |||||||||
Purchase of reserves in-place | 462,504,519 | 7,485,998 | 16,212,356 | |||||||||
Transfers to limited partnerships | — | — | — | |||||||||
Revisions(5) | (27,760,192 | ) | (153,413 | ) | 206,091 | |||||||
Production | (25,403,318 | ) | (120,736 | ) | (356,550 | ) | ||||||
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Balance, December 31, 2012 | 573,774,257 | 8,868,836 | 16,061,897 | |||||||||
Proved developed reserves at: | ||||||||||||
January 1, 2010 | 140,392,057 | 1,785,712 | — | |||||||||
December 31, 2010 | 137,393,017 | 1,832,535 | — | |||||||||
December 31, 2011 | 138,403,225 | 1,638,083 | — | |||||||||
December 31, 2012 | 338,655,324 | 3,400,447 | 7,884,778 | |||||||||
Proved undeveloped reserves at: | ||||||||||||
January 1, 2010 | 43,262,907 | 37,010 | — | |||||||||
December 31, 2010 | 38,671,986 | — | — | |||||||||
December 31, 2011 | 19,273,206 | 8,216 | — | |||||||||
December 31, 2012 | 235,118,932 | 5,468,389 | 8,177,120 |
(1) | Oil includes NGL information for the years ended December 31, 2011 and 2010, which was less than 500 MBbls. |
(2) | Principally includes increases of proved reserves due to the addition of Marcellus wells. |
(3) | Represents a downward revision, and related impairment charge, related to ARP’s shallow natural gas wells in Pennsylvania and Ohio, principally due to the reduction of drilling plans in the Clinton/Medina and Upper Devonian formations over the next five years. |
(4) | Represents a downward revision of proved undeveloped reserves in the New Albany Shale due to the reduction of certain drilling plans related to ARP’s shallow natural gas wells, as well as a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Colorado. |
(5) | Represents a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Michigan and Colorado due to declines in the average 1st day of the month price for the year ended December 31, 2012 as compared with the year ended December 31, 2011. |
Capitalized Costs Related to Oil and Gas Producing Activities.The components of capitalized costs related to oil and gas producing activities of ARP during the periods indicated were as follows (in thousands):
Years Ended December 31, | ||||||||
2012 | 2011 | |||||||
Natural gas and oil properties: | ||||||||
Proved properties | $ | 1,468,886 | $ | 892,907 | ||||
Unproved properties | 292,053 | 43,253 | ||||||
Support equipment | 13,110 | 9,413 | ||||||
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1,774,049 | 945,573 | |||||||
Accumulated depreciation, depletion and amortization | (504,625 | ) | (451,924 | ) | ||||
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Net capitalized costs | $ | 1,269,424 | $ | 493,649 | ||||
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Results of Operations from Oil and Gas Producing Activities. The results of operations related to ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Revenues | $ | 92,901 | $ | 66,979 | $ | 93,050 | ||||||
Production costs | (26,624 | ) | (17,100 | ) | (23,323 | ) | ||||||
Depreciation, depletion and amortization | (47,000 | ) | (27,430 | ) | (36,668 | ) | ||||||
Asset impairment(1) | (9,507 | ) | (6,995 | ) | (50,669 | ) | ||||||
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$ | 9,770 | $ | 15,454 | $ | (17,610 | ) | ||||||
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(1) | During the year ended December 31, 2012, ARP recognized $9.5 million of impairment related to its shallow natural gas wells in the Antrim and Niobrara Shales. During the year ended December 31, 2011, ARP recognized $7.0 million of impairment related to its shallow natural gas wells in the Niobrara Shale. During the year ended December 31, 2010, ARP recognized $50.7 million of impairment related to its shallow natural gas wells in the Chattanooga and Upper Devonian shales. |
Costs Incurred in Oil and Gas Producing Activities.The costs incurred by ARP in its oil and gas activities during the periods indicated are as follows (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Property acquisition costs: | ||||||||||||
Proved properties | $ | 528,684 | $ | 9,199 | $ | 3,007 | ||||||
Unproved properties | 213,638 | 323 | 2,259 | |||||||||
Exploration costs(1) | 1,026 | 1,156 | — | |||||||||
Development costs | 83,538 | 29,809 | 74,821 | |||||||||
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Total costs incurred in oil & gas producing activities | $ | 826,886 | $ | 40,487 | $ | 80,087 | ||||||
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(1) | There were no exploratory wells drilled during the years ended December 31, 2012, 2011 and 2010. |
The following schedule presents the standardized measure of estimated discounted future net cash flows relating to ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2012, 2011 and 2010, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Future cash inflows | $ | 2,930,514 | $ | 949,286 | $ | 1,045,725 | ||||||
Future production costs | (1,185,084 | ) | (425,493 | ) | (464,392 | ) | ||||||
Future development costs | (441,423 | ) | (27,266 | ) | (35,357 | ) | ||||||
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Future net cash flows | 1,304,007 | 496,527 | 545,976 | |||||||||
Less 10% annual discount for estimated timing of cash flows | (680,331 | ) | (276,668 | ) | (309,346 | ) | ||||||
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Standardized measure of discounted future net cash flows | $ | 623,676 | $ | 219,859 | $ | 236,630 | ||||||
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The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands), including amounts related to asset retirement obligations. Since ARP allocates taxable income to its owner, no recognition has been given to income taxes:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Balance, beginning of year | $ | 219,859 | $ | 236,630 | $ | 178,818 | ||||||
Increase (decrease) in discounted future net cash flows: | ||||||||||||
Sales and transfers of oil and gas, net of related costs | (54,969 | ) | (46,304 | ) | (51,522 | ) | ||||||
Net changes in prices and production costs | (87 | ) | (34 | ) | 41,978 | |||||||
Revisions of previous quantity estimates | (6,378 | ) | 757 | 21,598 | ||||||||
Development costs incurred | 575 | 1,842 | 7,565 | |||||||||
Changes in future development costs | — | (3,591 | ) | (803 | ) | |||||||
Transfers to limited partnerships | — | (8,022 | ) | (4,148 | ) | |||||||
Extensions, discoveries, and improved recovery less related costs | 64 | 14,923 | 54,887 | |||||||||
Purchases of reserves in-place | 510,467 | 736 | 492 | |||||||||
Sales of reserves in-place | — | (1 | ) | (12,254 | ) | |||||||
Accretion of discount | 21,986 | 23,663 | 17,882 | |||||||||
Estimated settlement of asset retirement obligations | (2,823 | ) | (3,105 | ) | (6,074 | ) | ||||||
Estimated proceeds on disposals of well equipment | 3,806 | 3,363 | 2,227 | |||||||||
Changes in production rates (timing) and other | (68,824 | ) | (998 | ) | (14,016 | ) | ||||||
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Outstanding, end of year | $ | 623,676 | $ | 219,859 | $ | 236,630 | ||||||
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NOTE 22 – QUARTERLY RESULTS (Unaudited)
Fourth Quarter(1) | Third Quarter(1) | Second Quarter(1) | First Quarter(1) | |||||||||||||
(in thousands, except unit data) | ||||||||||||||||
Year ended December 31, 2012: | ||||||||||||||||
Revenues | $ | 439,004 | $ | 354,773 | $ | 363,039 | $ | 364,627 | ||||||||
Income (loss) from continuing operations | $ | (31,917 | ) | $ | (21,392 | ) | $ | 51,570 | $ | (15,142 | ) | |||||
Income (loss) from discontinued operations | — | — | — | — | ||||||||||||
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Net income (loss) | (31,917 | ) | (21,392 | ) | 51,570 | (15,142 | ) | |||||||||
(Income) loss attributable to non-controlling interests | 17,042 | 9,982 | (59,191 | ) | (3,365 | ) | ||||||||||
(Income) loss 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) | — | — | — | — | ||||||||||||
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Net loss attributable to common limited partners | $ | (14,875 | ) | $ | (11,410 | ) | $ | (7,621 | ) | $ | (18,507 | ) | ||||
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Net income (loss) attributable to common limited partners per unit – basic: | ||||||||||||||||
Loss from continuing operations attributable to common limited partners | $ | (0.29 | ) | $ | (0.22 | ) | $ | (0.15 | ) | $ | (0.36 | ) | ||||
Income from discontinued operations attributable to common limited partners | — | — | — | — | ||||||||||||
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Net loss attributable to common limited partners | $ | (0.29 | ) | $ | (0.22 | ) | $ | (0.15 | ) | $ | (0.36 | ) | ||||
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(1) | For the first, second, third and fourth quarters of the year ended December 31, 2012, approximately 2,260,000, 3,084,000, 3,011,000 and 3,111,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |
Fourth Quarter(1) | Third Quarter | Second Quarter | First Quarter | |||||||||||||
(in thousands, except unit data) | ||||||||||||||||
Year ended December 31, 2011: | ||||||||||||||||
Revenues | $ | 415,535 | $ | 441,400 | $ | 408,837 | $ | 304,802 | ||||||||
Income (loss) from continuing operations | $ | (9,628 | ) | $ | 50,907 | $ | 24,438 | $ | 241,710 | |||||||
Income (loss) from discontinued operations | — | — | — | (81 | ) | |||||||||||
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Net income (loss) | (9,628 | ) | 50,907 | 24,438 | 241,629 | |||||||||||
(Income) loss attributable to non-controlling interests | 5,454 | (43,794 | ) | (7,925 | ) | (211,378 | ) | |||||||||
(Income) loss 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 | ) | |||||||||||
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Net income (loss) attributable to common limited partners | $ | (4,174 | ) | $ | 7,113 | $ | 16,513 | $ | 25,540 | |||||||
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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 | $ | (0.08 | ) | $ | 0.13 | $ | 0.31 | $ | 0.65 | |||||||
Income from discontinued operations attributable to common limited partners | — | — | — | — | ||||||||||||
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Net income (loss) attributable to common limited partners | $ | (0.08 | ) | $ | 0.13 | $ | 0.31 | $ | 0.65 | |||||||
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(1) | For the fourth quarter of the year ended December 31, 2011, approximately 1,933,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive. |
NOTE 23 – RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS
The Partnership has restated the consolidated combined statements of comprehensive income (loss) for the years ended December 31, 2012, 2011 and 2010 of the Partnership and subsidiaries to reorder certain line items and subtotals presented, separately disclose within such statements the amounts of total other comprehensive income (loss), consolidated comprehensive income (loss), including amounts attributable to the common limited partners and attributable to non-controlling interests, and to revise certain headings in such financial statements. The previously reported amounts of comprehensive income (loss) attributable to common limited partners did not change for any period.
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ITEM 9A: | CONTROLS AND PROCEDURES |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, excluding assets acquired from Titan, DTE and Cardinal. As described below, subsequent to the filing of the Original Filing, a material weakness was identified in our internal control over financial reporting. As a result of the material weakness, management has concluded that our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2012.
Management’s Report on Internal Control over Financial Reporting
The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (COSO framework).
An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.
In conducting management’s evaluation of the effectiveness of its internal control over financial reporting, management has excluded, due to the timing, size, and complexity, the operations of ARP’s newly acquired assets from Titan and DTE, which were acquired in July 2012 and December 2012, respectively, and APL’s newly acquired assets from Cardinal from its December 31, 2012 Sarbanes-Oxley 404 review (see “Item 8. Financial Statements and Supplemental Data – Note 4”). In connection with these acquisitions, ARP and APL have entered into transition services agreements with the previous owners. As a result, ARP did not begin to perform substantially all accounting control functions related to its Titan acquisition until January 1, 2013 and ARP and APL will not begin to perform accounting control functions related to the DTE and Cardinal acquisitions until March 1, 2013 and March 20, 2013, respectively. Titan, DTE and Cardinal constituted 5%, 6% and 16%, respectively, of our total assets and less than 1%, respectively, of our total revenues for the year ended December 31, 2012. We are continuing to integrate these systems’ historical internal controls over financial reporting with our existing internal controls over financial reporting. This integration may lead to changes in our or the acquired systems’ historical internal controls over financial reporting in future fiscal reporting periods. In April 2012, ARP acquired certain assets from Carrizo, which have been fully integrated into our existing internal control environment. Other than the previously mentioned items, there have been no changes in our internal control over financial reporting during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Based on our evaluation under the COSO framework in connection with the Original Filing, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2012. Subsequent to the filing of the Original Filing, as a result of the monitoring and application of appropriate authoritative financial statement presentation rules, management identified a material weakness that existed as of December 31, 2012 related to the monitoring and application of appropriate authoritative accounting rules. A material weakness is a deficiency, or combination of deficiencies, that results in more than a remote likelihood that a material misstatement of financial statements will not be prevented, or detected and corrected, on a timely basis. As a result of the material weakness, management has concluded that our internal control over financial reporting was ineffective as of December 31, 2012. Accordingly, management has restated its report on internal control over financial reporting. The restated report reflects disclosure controls and procedures in place, and events that had occurred, as of December 31, 2012.
The material weakness resulted in the reordering and renaming of certain line items within the consolidated combined statements of comprehensive income (loss).
To remediate the material weakness described above and enhance our internal control over financial reporting, management has implemented a more formal review of the consolidated combined statements of comprehensive income (loss). As of June 30, 2013, the material weakness described above has been remediated.
Grant Thornton LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2012, which is included herein.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Unitholders
Atlas Energy, L.P.
We have audited the internal control over financial reporting of Atlas Energy, L.P. (a Delaware limited partnership) and subsidiaries (collectively the “Partnership”) as of December 31, 2012, based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of Titan, DTE and Cardinal, which are wholly-owned subsidiaries, whose financial statements reflect aggregate total assets and revenues constituting 27% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2012. As indicated in Management’s Report, Titan, DTE and Cardinal were acquired during 2012, and therefore, management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Titan, DTE and Cardinal.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment.
A material weakness related to the monitoring and application of appropriate authoritative accounting rules was identified and included in management’s assessment.
In our report dated February 28, 2013, we expressed an unqualified opinion on the Partnership’s internal control over financial reporting. The material weakness discussed above was subsequently identified in connection with the restatement of the Partnership’s previously issued financial statements. Accordingly, management has revised its assessment about the effectiveness of the Partnership’s internal control over financial reporting, and our present opinion on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2012, as presented herein, is different than that expressed in our previous report. The material weakness was considered in connection with the aforementioned restatement, and this does not affect our opinion on the Partnership’s 2012 financial statements.
In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, the Partnership has not maintained effective internal control over financial reporting as of December 31, 2012, based on criteria established inInternal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated combined financial statements of the Partnership as of and for the year ended December 31, 2012, and our report dated February 28, 2013 (except as disclosed in Note 23, as to which the date is October 22, 2013) expressed an unqualified opinion on those financial statements.
We do not express an opinion or any other form of assurance on management’s statement referring to the steps taken to remediate the identified material weakness.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
February 28, 2013 (except for the material weakness and the effects thereof discussed in Management’s Report on Internal Control over Financial Reporting, as revised, as to which the date is October 22, 2013)
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PART IV
ITEM 15: | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
(a) | The following documents are filed as part of this report: |
(1) | Financial Statements |
The financial statements required by this Item 15(a)(1) are set forth in Item 8: Financial Statements and Supplementary Data.
(2) | Financial Statement Schedules |
None
(3) | Exhibits: |
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. (11) | |
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. (11) | |
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. (11) | |
2.4 | Separation and Distribution Agreement, dated February 23, 2012, by and among Atlas Energy, L.P., Atlas Energy GP, LLC, Atlas Resource Partners, L.P. and Atlas Resource Partners GP, LLC. (The schedules to the Separation and Distribution Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.) (27) | |
3.1(a) | Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.(1) | |
3.1(b) | Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.(13) | |
3.1(c) | Amendment to Certificate of Limited Partnership of Atlas Energy, L.P. (5) | |
3.2(a) | Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(13) | |
3.2(b) | Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.(13) | |
3.2(c) | Amendment No. 2 to Second Amended and Restated Limited Partnership Agreement of Atlas Energy, L.P. (5) | |
4.1 | Specimen Certificate Representing Common Units(1) | |
10.1 | Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC. (13) | |
10.2 | Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(1) | |
10.3(a) | Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1) |
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Exhibit No. | Description | |
10.3(b) | Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(4) | |
10.3(c) | Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.3(d) | Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.3(e) | Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6) | |
10.3(f) | Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(7) | |
10.3(g) | Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(8) | |
10.3(h) | Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(9) | |
10.3(i) | Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(14) | |
10.4 | Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC(33) | |
10.5(a) | Amended and Restated Limited Partnership Agreement of Atlas Resource Partners, L.P.(28) | |
10.5(b) | Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P. dated as of July 25, 2012(17) | |
10.6(a) | Long-Term Incentive Plan(6) | |
10.6(b) | Amendment No. 1 to Long-Term Incentive Plan(15) | |
10.7 | 2010 Long-Term Incentive Plan(16) | |
10.8 | Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan(32) | |
10.9 | Form of Stock Option Grant under 2010 Long-Term Incentive Plan(32) | |
10.10(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) | |
10.10(b) | Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011 (25) | |
10.10(c) | Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011 (26) | |
10.10(d) | Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of May 31, 2012(18) |
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Exhibit No. | Description | |
10.10(e) | Amendment No. 3 to the Amended and Restated Credit Agreement(34) | |
10.11 | 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) | |
10.12(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) | |
10.12(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) | |
10.12(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) | |
10.13 | 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) | |
10.14 | 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) | |
10.15 | 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) | |
10.16 | Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011(12) | |
10.17 | Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011(12) |
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Exhibit No. | Description | |
10.18 | Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011(21) | |
10.19 | Employment Agreement between Atlas Energy, L.P. and Matthew A. Jones dated as of November 4, 2011(32) | |
10.20 | Employment Agreement between Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Patrick J. McDonie dated as of July 3, 2012 (35) | |
10.21 | Form of Grant of Phantom Units to Non-Employee Managers(20) | |
10.22 | Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010(21) | |
10.23 | Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010(22) | |
10.24 | Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010(22) | |
10.25(a) | Credit Agreement, dated as of March 5, 2012, among Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (30) | |
10.25(b) | First Amendment to Credit Agreement, dated as of April 30, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (31) | |
10.25(c) | Joinder Agreement dated April 18, 2012 between ARP Barnett, LLC, ARP Oklahoma, LLC and Wells Fargo Bank, N.A.(31) | |
10.25(d) | Joinder Agreement dated April 30, 2012 between ARP Barnett, LLC and Wells Fargo Bank, N.A.(31) | |
10.25(e) | Second Amendment to Amended and Restated Credit Agreement, dated as of July 26, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (17) | |
10.25(f) | Joinder Agreement dated as of July 26, 2012 between Atlas Barnett, LLC and Wells Fargo Bank, N.A. (17) | |
10.25(g) | Third Amendment to Amended and Restated Credit Agreement dated as of December 20, 2012(36) | |
10.25(h) | Fourth Amendment to Amended and Restated Credit Agreement dated as of January 11, 2013(37) | |
10.26 | Secured Hedge Facility Agreement dated as of March 5, 2012 among Atlas Resources, LLC, the participating partnerships from time to time party thereto, the hedge providers from time to time party thereto and Wells Fargo Bank, N.A., as collateral agent for the hedge providers(30) | |
10.27 | Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan(28) | |
10.28 | Purchase and Sale Agreement, dated as of March 15, 2012, among ARP Barnett, LLC, Carrizo Oil & Gas, Inc., CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, Inc. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request(29) | |
10.29 | Credit Agreement, dated as of May 16, 2012, among Atlas Energy, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (2) |
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Exhibit No. | Description | |
10.30 | Merger Agreement dated as of May 17, 2012 among Atlas Resource Partners, L.P., Titan Merger Sub, LLC and Titan Operating, LLC. The annexes, schedules and exhibits to the Merger Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted annexes, schedules and exhibits will be furnished to the U.S. Securities and Exchange Commission supplementally upon request(3) | |
10.31 | Membership Interest Purchase Agreement, dated as of November 29, 2012, between MCN EnergyEnterprises, LLC and Atlas Barnett, LLC. The schedules to the Membership Interest Purchase Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request(38) | |
10.32 | Securities Purchase Agreement dated November 30, 2012, by and among Cardinal Midstream, LLC, Cardinal Arkoma, Inc., Cardinal Arkoma Midstream, LLC, Cardinal Gas Treating LLC and Atlas Pipeline Mid-Continent Holdings, LLC. The schedules to the Securities Purchase Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request(39) | |
10.33 | Registration Rights Agreement, dated as of April 30, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein(31) | |
10.34 | Registration Rights Agreement, dated as of July 25, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein(17) | |
10.35 | Registration Rights Agreement, dated as of May 16, 2012, between Atlas Resource Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Credit Agreement dated May 16, 2012 by and among Atlas Energy, L.P. and the lenders named therein(40) | |
10.36 | Second Lien Credit Agreement, dated as of December 20, 2012, by and among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Energy Capital, Inc. as administrative agent for the lenders(36) | |
10.37 | Registration Rights Agreement, dated as of January 23, 2013 among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation and the initial purchasers named therein(10) | |
10.38 | Registration Rights Agreement, dated May 16, 2012, between Atlas Pipeline Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Credit Agreement dated May 16, 2012 by and among Atlas Energy, L.P. and the lenders named therein(35) | |
10.39 | Registration Rights Agreement, dated September 28, 2012, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein(41) | |
10.40 | Registration Rights Agreement, dated December 20, 2012, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein(42) | |
10.41 | Equity Distribution Agreement dated November 5, 2012, by and between Atlas Pipeline Partners, L.P. and Citigroup Global Markets Inc.(43) | |
21.1 | Subsidiaries of Registrant(45) | |
23.1 | Consent of Grant Thornton LLP |
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Exhibit No. | Description | |
23.2 | Consent of Wright & Company, Inc. | |
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 | |
99.1 | Summary Reserve Report(44) | |
101.INS | XBRL Instance Document(46) | |
101.SCH | XBRL Schema Document(46) | |
101.CAL | XBRL Calculation Linkbase Document(46) | |
101.LAB | XBRL Label Linkbase Document(46) | |
101.PRE | XBRL Presentation Linkbase Document(46) | |
101.DEF | XBRL Definition Linkbase Document(46) |
(1) | Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999). |
(2) | Previously filed as an exhibit to current report on Form 8-K filed May 21, 2012. |
(3) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 21, 2012. |
(4) | Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007. |
(5) | Previously filed as an exhibit to current report on Form 8-K filed December 13, 2011. |
(6) | Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008. |
(7) | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009. |
(8) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 2, 2010. |
(9) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 7, 2010. |
(10) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 25, 2013. |
(11) | Previously filed as an exhibit to current report on Form 8-K filed November 12, 2010. |
(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 December 13, 2011. |
(15) | Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2010. |
(16) | Previously filed as an exhibit to current report on Form 8-K filed on November 12, 2010. |
(17) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 26, 2012. |
(18) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 31, 2012. |
(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 Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2011. |
(22) | Previously filed as an exhibit to Atlas Energy, Inc.’s current report on Form 8-K filed on November 12, 2010. |
(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 Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011. |
(26) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 11, 2011. |
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(27) | Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2012. |
(28) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 14, 2012. |
(29) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 21, 2012. |
(30) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 7, 2012. |
(31) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 1, 2012. |
(32) | Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2011. |
(33) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2012. |
(34) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 13, 2012. |
(35) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended June 30, 2012. |
(36) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on December 26, 2012. |
(37) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 11, 2013. |
(38) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on November 20, 2012. |
(39) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 4, 2012. |
(40) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended June 30, 2012. |
(41) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on September 28, 2012. |
(42) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 26, 2012. |
(43) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on November 6, 2012. |
(44) | Previously filed as an exhibit to Atlas Resource Partners, L.P.’s annual report on Form 10-K filed on February 28, 2013. |
(45) | Previously filed as an exhibit to the Original Filing. |
(46) | 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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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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: October 22, 2013 | By: | /S/ SEAN P. MCGRATH | ||||
Sean P. McGrath Chief Financial Officer |
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