UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
(Amendment No. 1)
(Mark One)
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2013
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 1-32953
ATLAS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 43-2094238 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
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
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The number of outstanding common units of the registrant on May 1, 2013 was 51,373,496.
EXPLANATORY NOTE
This Amendment No. 1 on Form 10-Q/A (the “Amendment”) amends Atlas Energy, L.P.’s (the “Partnership”) Quarterly Report on Form 10-Q for the three months ended March 31, 2013, as originally filed with the Securities and Exchange Commission on May 9, 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 I—Item 1 “Financial Statements” to revise the consolidated 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 revise certain headings in such financial statements;
(b) Part I—Item 4 “Controls and Procedures” to include a discussion of a material weakness identified subsequent to the Original Filing; and
(c) Part II—Item 6 “Exhibits” to indicate that 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 either period.
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
(Unaudited)
March 31, 2013 | December 31, 2012 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 11,408 | $ | 36,780 | ||||
Accounts receivable | 203,919 | 196,249 | ||||||
Current portion of derivative asset | 19,160 | 35,351 | ||||||
Subscriptions receivable | — | 55,357 | ||||||
Prepaid expenses and other | 47,493 | 45,255 | ||||||
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Total current assets | 281,980 | 368,992 | ||||||
Property, plant and equipment, net | 3,657,898 | 3,502,609 | ||||||
Intangible assets, net | 184,038 | 200,680 | ||||||
Investment in joint venture | 86,242 | 86,002 | ||||||
Goodwill, net | 351,069 | 351,069 | ||||||
Long-term derivative asset | 6,583 | 16,840 | ||||||
Other assets, net | 81,666 | 71,002 | ||||||
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$ | 4,649,476 | $ | 4,597,194 | |||||
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LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 8,861 | $ | 10,835 | ||||
Accounts payable | 130,118 | 119,028 | ||||||
Liabilities associated with drilling contracts | 10,815 | 67,293 | ||||||
Accrued producer liabilities | 114,057 | 109,725 | ||||||
Current portion of derivative liability | 10,627 | — | ||||||
Current portion of derivative payable to Drilling Partnerships | 8,665 | 11,293 | ||||||
Accrued interest | 9,592 | 11,556 | ||||||
Accrued well drilling and completion costs | 70,524 | 47,637 | ||||||
Accrued liabilities | 60,681 | 103,291 | ||||||
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Total current liabilities | 423,940 | 480,658 | ||||||
Long-term debt, less current portion | 1,740,051 | 1,529,508 | ||||||
Long-term derivative liability | 3,617 | 888 | ||||||
Long-term derivative payable to Drilling Partnerships | 670 | 2,429 | ||||||
Deferred income taxes, net | 30,249 | 30,258 | ||||||
Asset retirement obligations and other | 76,360 | 73,605 | ||||||
Commitments and contingencies | ||||||||
Partners’ Capital: | ||||||||
Common limited partners’ interests | 433,320 | 456,171 | ||||||
Accumulated other comprehensive income (loss) | (1,964 | ) | 9,699 | |||||
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431,356 | 465,870 | |||||||
Non-controlling interests | 1,943,233 | 2,013,978 | ||||||
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Total partners’ capital | 2,374,589 | 2,479,848 | ||||||
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$ | 4,649,476 | $ | 4,597,194 | |||||
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See accompanying notes to consolidated financial statements.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Revenues: | ||||||||
Gas and oil production | $ | 46,064 | $ | 17,164 | ||||
Well construction and completion | 56,478 | 43,719 | ||||||
Gathering and processing | 420,087 | 305,141 | ||||||
Administration and oversight | 1,085 | 2,831 | ||||||
Well services | 4,816 | 5,006 | ||||||
Loss on mark-to-market derivatives | (12,083 | ) | (12,035 | ) | ||||
Other, net | 5,655 | 2,801 | ||||||
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Total revenues | 522,102 | 364,627 | ||||||
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Costs and expenses: | ||||||||
Gas and oil production | 15,216 | 4,505 | ||||||
Well construction and completion | 49,112 | 37,695 | ||||||
Gathering and processing | 351,741 | 251,845 | ||||||
Well services | 2,318 | 2,430 | ||||||
General and administrative | 40,658 | 37,248 | ||||||
Depreciation, depletion and amortization | 51,666 | 29,950 | ||||||
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Total costs and expenses | 510,711 | 363,673 | ||||||
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Operating income | 11,391 | 954 | ||||||
Loss on asset sales and disposal | (702 | ) | (7,005 | ) | ||||
Interest expense | (25,810 | ) | (9,091 | ) | ||||
Loss on early extinguishment of debt | (26,582 | ) | — | |||||
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Net loss before tax | (41,703 | ) | (15,142 | ) | ||||
Income tax benefit | 9 | — | ||||||
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Net loss | (41,694 | ) | (15,142 | ) | ||||
Loss (income) attributable to non-controlling interests | 29,098 | (3,365 | ) | |||||
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Net loss attributable to common limited partners | $ | (12,596 | ) | $ | (18,507 | ) | ||
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Net loss attributable to common limited partners per unit: | ||||||||
Basic | $ | (0.25 | ) | $ | (0.36 | ) | ||
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Diluted | $ | (0.25 | ) | $ | (0.36 | ) | ||
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Weighted average common limited partner units outstanding: | ||||||||
Basic | 51,369 | 51,294 | ||||||
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Diluted | 51,369 | 51,294 | ||||||
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See accompanying notes to consolidated financial statements.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
(Unaudited)
(As Restated)
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Net loss | $ | (41,694 | ) | $ | (15,142 | ) | ||
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Other comprehensive income (loss): | ||||||||
Changes in fair value of derivative instruments accounted for as cash flow hedges | (24,944 | ) | 14,169 | |||||
Less: reclassification adjustment for realized gains of cash flow hedges in net income (loss) | (993 | ) | (1,454 | ) | ||||
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Total other comprehensive income (loss) | (25,937 | ) | 12,715 | |||||
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Comprehensive income (loss) | (67,631 | ) | (2,427 | ) | ||||
Comprehensive (income) loss attributable to non-controlling interests | 43,372 | (12,495 | ) | |||||
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Comprehensive loss attributable to common limited partners | $ | (24,259 | ) | $ | (14,922 | ) | ||
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See accompanying notes to consolidated financial statements.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(in thousands, except unit data)
(Unaudited)
Common Limited Partners’ Capital | Accumulated Other Comprehensive Income (Loss) | Non- Controlling Interest | Total Partners’ Capital | |||||||||||||||||
Units | Amount | |||||||||||||||||||
Balance at January 1, 2013 | 51,365,582 | $ | 456,171 | $ | 9,699 | $ | 2,013,978 | $ | 2,479,848 | |||||||||||
Distributions to non-controlling interests | — | — | — | (46,907 | ) | (46,907 | ) | |||||||||||||
Unissued common units under incentive plan | — | 5,522 | — | 8,514 | 14,036 | |||||||||||||||
Issuance of units under incentive plans | 7,914 | — | — | 63 | 63 | |||||||||||||||
Distributions paid to common limited partners | — | (15,410 | ) | — | — | (15,410 | ) | |||||||||||||
Distribution equivalent rights paid on unissued units under incentive plans | — | (683 | ) | — | (1,091 | ) | (1,774 | ) | ||||||||||||
Atlas Pipeline Partners, L.P. purchase price allocation | — | — | — | (1,780 | ) | (1,780 | ) | |||||||||||||
Gain on issuance of Atlas Pipeline Partners, L.P.’s common units | — | 316 | — | (316 | ) | — | ||||||||||||||
Non-controlling interests’ capital contribution | — | — | — | 14,144 | 14,144 | |||||||||||||||
Other comprehensive loss | — | — | (11,663 | ) | (14,274 | ) | (25,937 | ) | ||||||||||||
Net loss | — | (12,596 | ) | — | (29,098 | ) | (41,694 | ) | ||||||||||||
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Balance at March 31, 2013 | 51,373,496 | $ | 433,320 | $ | (1,964 | ) | $ | 1,943,233 | $ | 2,374,589 | ||||||||||
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See accompanying notes to consolidated financial statements.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net loss | $ | (41,694 | ) | $ | (15,142 | ) | ||
Adjustments to reconcile net loss to net cash used in operating activities: | ||||||||
Depreciation, depletion and amortization | 51,666 | 29,950 | ||||||
Amortization of deferred financing costs | 6,246 | 1,359 | ||||||
Non-cash loss on derivative value, net | 9,480 | 3,351 | ||||||
Non-cash compensation expense | 14,153 | 4,759 | ||||||
Loss on asset sales and disposal | 702 | 7,005 | ||||||
Deferred income tax benefit | (9 | ) | — | |||||
Loss on early extinguishment of debt | 26,582 | — | ||||||
Distributions paid to non-controlling interests | (47,998 | ) | (26,502 | ) | ||||
Equity income in unconsolidated companies | (2,039 | ) | (1,233 | ) | ||||
Distributions received from unconsolidated companies | 1,804 | 1,996 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable and prepaid expenses and other | 44,100 | 50,810 | ||||||
Accounts payable and accrued liabilities | (84,766 | ) | (60,845 | ) | ||||
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Net cash used in operating activities | (21,773 | ) | (4,492 | ) | ||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Capital expenditures | (167,003 | ) | (100,125 | ) | ||||
Net cash paid for acquisitions | — | (17,235 | ) | |||||
Other | (1,498 | ) | (941 | ) | ||||
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Net cash used in investing activities | (168,501 | ) | (118,301 | ) | ||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Borrowings under credit facilities | 400,000 | 336,500 | ||||||
Repayments under credit facilities | (743,925 | ) | (231,500 | ) | ||||
Net proceeds from issuance of Atlas Pipeline Partners, L.P.’s long-term debt | 637,090 | — | ||||||
Net proceeds from issuance of Atlas Resource Partners, L.P.’s long-term debt | 267,926 | — | ||||||
Repayments of Atlas Pipeline Partners, L.P. long-term debt | (365,822 | ) | — | |||||
Net proceeds from Atlas Pipeline Partners, L.P. equity offering | 14,144 | — | ||||||
Distributions paid to unitholders | (15,410 | ) | (12,310 | ) | ||||
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt | (25,562 | ) | — | |||||
Deferred financing costs and other | (3,539 | ) | (1,924 | ) | ||||
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Net cash provided by financing activities | 164,902 | 90,766 | ||||||
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Net change in cash and cash equivalents | (25,372 | ) | (32,027 | ) | ||||
Cash and cash equivalents, beginning of year | 36,780 | 77,376 | ||||||
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Cash and cash equivalents, end of period | $ | 11,408 | $ | 45,349 | ||||
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See accompanying notes to consolidated financial statements.
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ATLAS ENERGY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2013
(Unaudited)
NOTE 1 – BASIS OF PRESENTATION
Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership (NYSE: ATLS).
At March 31, 2013, 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, crude oil and NGL production activities. At March 31, 2013, the Partnership owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 43.0% limited partner interest (20,962,485 common limited partner units) 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 March 31, 2013, 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 March 31, 2013, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 6). |
In February 2012, the board of directors (“the Board”) of the Partnership’s General Partner (“the General Partner”) 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.
The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2012 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. Certain amounts in the prior year’s consolidated 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 three months ended March 2012 to be consistent with the three months ended March 31, 2013. The results of operations for the three months ended March 31, 2013 may not necessarily be indicative of the results of operations for the full year ending December 31, 2013.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Combination
The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at March 31, 2013, except for ARP and APL, which are controlled by the Partnership. Due to the
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structure of the Partnership’s ownership interests in ARP and APL, the Partnership consolidates the financial statements of ARP and APL into its consolidated 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 statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated.
In accordance with established practice in the oil and gas industry, the Partnership’s consolidated 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 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 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 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 (the “Cardinal Acquisition”) (see Note 3). 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 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 3).
Use of Estimates
The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated 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. Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2013 and 2012 represent actual results in all material respects (see“Revenue Recognition”).
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 March 31, 2013 and December 31, 2012, ARP and APL had recorded no allowance for uncollectible accounts receivable on the Partnership’s consolidated balance sheets.
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Inventory
ARP and APL had $13.8 million and $13.5 million of inventory at March 31, 2013 and December 31, 2012, 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.
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 Drilling 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 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 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
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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.
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 three months ended March 31, 2013 and 2012.
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 impairments 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. These impairments related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2012. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. There were no impairments of proved gas and oil properties recorded by ARP for the three months ended March 31, 2013 and 2012.
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 6.1% and 6.7% for the three months ended March 31, 2013 and 2012, respectively. The aggregate amounts of interest capitalized by ARP and APL were $5.9 million and $2.3 million for the three months ended March 31, 2013 and 2012, respectively.
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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 it 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. During the year ended December 31, 2012, APL completed an acquisition of a gas gathering system and related assets, which it accounted for as a business combination and initially recognized $10.6 million as customer contract intangible assets in its preliminary purchase price allocation. APL revised its preliminary acquisition purchase price allocation during the three months ended March 31, 2013, including an $8.4 million reduction of the fair value of intangible assets with finite lives. APL’s purchase price allocation for the Cardinal Acquisition has not been completed as of March 31, 2013, and estimates of fair value reflected as of March 31, 2013 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 March 31, 2013 and December 31, 2012 (in thousands):
March 31, 2013 | December 31, 2012 | Estimated Useful Lives In Years | ||||||||
Gross Carrying Amount: | ||||||||||
Customer contracts and relationships | $ | 316,813 | $ | 325,246 | 7 – 14 | |||||
Partnership management and operating contracts | 14,344 | 14,344 | 13 | |||||||
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|
|
| |||||||
$ | 331,157 | $ | 339,590 | |||||||
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|
| |||||||
Accumulated Amortization: | ||||||||||
Customer contracts and relationships | $ | (134,027 | ) | $ | (125,886 | ) | ||||
Partnership management and operating contracts | (13,092 | ) | (13,024 | ) | ||||||
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|
|
| |||||||
$ | (147,119 | ) | $ | (138,910 | ) | |||||
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| |||||||
Net Carrying Amount: | ||||||||||
Customer contracts and relationships | $ | 182,786 | $ | 199,360 | ||||||
Partnership management and operating contracts | 1,252 | 1,320 | ||||||||
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|
|
| |||||||
$ | 184,038 | $ | 200,680 | |||||||
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Amortization expense on intangible assets was $8.2 million and $5.9 million for the three months ended March 31, 2013 and 2012, 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 - $34.2 million; 2014 - $31.0 million; 2015 - $25.9 million; 2016 - $25.8 million; and 2017 - $19.8 million.
Goodwill
At March 31, 2013, the Partnership had $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 (see Note 3). The goodwill related to APL’s Cardinal Acquisition is a result of the strategic industry position of the assets and potential future synergies. The purchase price allocation for the Cardinal Acquisition has not been completed and the estimated goodwill allocation as of March 31, 2013 is subject to change and may be material. There were no changes in the carrying amount of goodwill for ARP and APL for the three months ended March 31, 2013.
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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 three months ended March 31, 2013, no impairment indicators arose and no goodwill impairments were recognized for ARP or APL by the Partnership.
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 8).
Derivative Instruments
ARP and APL enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 9). 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 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 7). 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 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 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. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the three months ended March 31, 2013 and 2012.
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 March 31, 2013, except for: 1) an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas
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Franchise Tax for franchise report years 2008 through 2011; 2) an examination by the IRS related to one of APL’s corporate subsidiaries’ Federal Corporate Return for the period ended December 31, 2011; and 3) an examination by the IRS related to one of ARP’s subsidiaries’ Federal Partnership 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 3), the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements as of March 31, 2013 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 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 11).
Stock-Based Compensation
The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their fair values (see Note 16).
Net Income (Loss) Per Common Unit
Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.
Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 16), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income 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) 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):
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Net loss | $ | (41,694 | ) | $ | (15,142 | ) | ||
Loss (income) attributable to non-controlling interests | 29,098 | (3,365 | ) | |||||
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| |||||
Net loss attributable to common limited partners | (12,596 | ) | (18,507 | ) | ||||
Less: Net income attributable to participating securities – phantom units(1) | — | — | ||||||
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| |||||
Net loss utilized in the calculation of net loss attributable to common limited partners per unit | $ | (12,596 | ) | $ | (18,507 | ) | ||
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(1) | Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended March 31, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,216,000 and 1,929,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. |
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 16).
The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Weighted average number of common limited partners per unit – basic | 51,369 | 51,294 | ||||||
Add effect of dilutive incentive awards(1) | — | — | ||||||
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|
| |||||
Weighted average number of common limited partners per unit – diluted | 51,369 | 51,294 | ||||||
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|
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(1) | For the three months ended March 31, 2013 and 2012, approximately 3,594,000 units and 2,260,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Revenue Recognition
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 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 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 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 two 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, 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:
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• | 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 NGL 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” for further description). ARP and APL had unbilled revenues at March 31, 2013 and December 31, 2012 of $121.6 million and $134.2 million, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.
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 U.S. GAAP, 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)” on the Partnership’s consolidated financial statements, and at March 31, 2013, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 9).
Recently Adopted Accounting Standards
In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.
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Recently Issued Accounting Standards
In February 2013, the FASB issued ASU 2013-04,Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement, and disclosure, of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
NOTE 3 – 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 14). 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 8).
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 10). 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 | 262,879 | |||
Other assets, net | 273 | |||
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Total assets acquired | $ | 276,288 | ||
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| |||
Liabilities: | ||||
Accounts payable | $ | 7,760 | ||
Accrued liabilities | 2,910 | |||
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Total current liabilities | 10,670 | |||
Asset retirement obligation and other | 8,169 | |||
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Total liabilities assumed | 18,839 | |||
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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 14). 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 14).
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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 10).
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 | |||
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Total assets acquired | $ | 216,591 | ||
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| |||
Liabilities: | ||||
Accounts payable | $ | 676 | ||
Revenue distribution payable | 3,091 | |||
Accrued liabilities | 1,816 | |||
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| |||
Total current liabilities | 5,583 | |||
Asset retirement obligation and other | 2,418 | |||
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Total liabilities assumed | 8,001 | |||
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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 14).
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 10).
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 | |||
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| |||
Net assets acquired | $ | 187,043 | ||
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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 and a 60% interest in Centrahoma. The remaining 40% ownership interest in
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Centrahoma is held by Mark-West Energy Partners, L.P. (NYSE: MWE) (“MarkWest”). 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 8); 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 14). APL funded the remaining purchase price from its senior secured revolving credit facility (see Note 8). 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 sheets at March 31, 2013 and 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 10). 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 | |||
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Total current assets | 24,241 | |||
Property, plant and equipment | 295,855 | |||
Intangible assets – contracts | 107,530 | |||
Goodwill | 310,904 | |||
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Total assets acquired | $ | 738,530 | ||
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Liabilities: | ||||
Current portion of long-term debt | 341 | |||
Accounts payable and accrued liabilities | 16,496 | |||
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Total current liabilities | 16,837 | |||
Deferred tax liability, net | 30,082 | |||
Long-term debt, less current portion | 604 | |||
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Total liabilities assumed | 47,523 | |||
Non-controlling interest | 89,310 | |||
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Net assets acquired | 601,697 | |||
Less cash received | (3,246 | ) | ||
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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.
NOTE 4 – APL EQUITY METHOD INVESTMENTS
The Partnership’s consolidated financial statements include APL’s 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”). APL accounts for its investment in the joint venture under the equity method of accounting. Under this method, APL recognizes its proportionate share of the joint ventures’ net income as equity income on the Partnership’s consolidated statements of operations. Equity investment in the WTLPG joint venture in excess of APL’s proportionate ownership interest in the underlying identifiable net assets of WTLPG that are allocable to property, plant and equipment or finite lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to equity investment on the Partnership’s consolidated balance sheet with an offsetting reduction to other, net on the Partnership’s
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consolidated statements of operations. Excess investment allocable to goodwill or infinite lived intangible assets is not amortized but is evaluated for impairment annually. No excess investment allocable to goodwill or infinite lived intangible assets was recognized on the acquisition of WTLPG. APL had $86.2 million and $86.0 million of equity method investment in WTLPG at March 31, 2013 and December 31, 2012, respectively, which was included within the investment in joint ventures on the Partnership’s consolidated balance sheets. APL also had recognized $2.0 million and $0.9 million of equity income within other, net on the Partnership’s consolidated statements of operations for the three months ended March 31, 2013 and 2012, respectively, related to its investment in WTLPG.
NOTE 5 – PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at the dates indicated (in thousands):
March 31, 2013 | December 31, 2012 | Estimated Useful Lives in Years | ||||||||||
Natural gas and oil properties: | ||||||||||||
Proved properties: | ||||||||||||
Leasehold interests | $ | 250,119 | $ | 244,476 | ||||||||
Pre-development costs | 3,106 | 1,935 | ||||||||||
Wells and related equipment | 1,288,734 | 1,222,475 | ||||||||||
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Total proved properties | 1,541,959 | 1,468,886 | ||||||||||
Unproved properties | 292,810 | 292,053 | ||||||||||
Support equipment | 13,488 | 13,110 | ||||||||||
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Total natural gas and oil properties | 1,848,257 | 1,774,049 | ||||||||||
Pipelines, processing and compression facilities | 2,446,247 | 2,326,186 | 2 – 40 | |||||||||
Rights of way | 181,151 | 179,018 | 20 – 40 | |||||||||
Land, buildings and improvements | 25,824 | 25,609 | 3 – 40 | |||||||||
Other | 28,482 | 26,656 | 3 – 10 | |||||||||
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4,529,961 | 4,331,518 | |||||||||||
Less – accumulated depreciation, depletion and amortization | (872,063 | ) | (828,909 | ) | ||||||||
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$ | 3,657,898 | $ | 3,502,609 | |||||||||
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During the three months ended March 31, 2013, ARP recognized a $0.7 million loss on asset disposal pertaining to its decision not to drill wells on leasehold property that expired during the three months ended March 31, 2013 in Indiana and Tennessee.
During the three months ended March 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 three months ended March 31, 2012.
During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments 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. These impairments related to the carrying amounts of gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2012. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
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NOTE 6 – OTHER ASSETS
The following is a summary of other assets at the dates indicated (in thousands):
March 31, 2013 | December 31, 2012 | |||||||
Deferred financing costs, net of accumulated amortization of $32,299 and $26,053 at March 31, 2013 and December 31, 2012, respectively | $ | 54,889 | $ | 45,629 | ||||
Investment in Lightfoot | 19,877 | 19,882 | ||||||
Security deposits | 2,265 | 2,390 | ||||||
Other | 4,635 | 3,101 | ||||||
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$ | 81,666 | $ | 71,002 | |||||
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Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). Amortization expense of deferred finance costs was $3.0 million and $1.4 million for the three months ended March 31, 2013 and 2012, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2013, ARP recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of senior unsecured notes due 2021 (“7.75% ARP Senior Notes”) (see Note 8). During the three months ended March 31, 2013, APL recorded $5.3 million of accelerated amortization of deferred financing costs related to the retirement of its 8.75% unsecured senior notes due 2018 (“8.75% APL Senior Notes) to loss on early extinguishment of debt on the Partnerships consolidated statement of operations (see Note 8). There was no accelerated amortization of deferred financing costs during the three months ended March 31, 2012.
At March 31, 2013, 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 (“MLPs”) and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the three months ended March 31, 2013 and 2012, the Partnership recognized equity loss of approximately $1,000 and equity income of $0.3 million, respectively, within other, net on the Partnership’s consolidated statements of operations. During the three months ended March 31, 2013 and 2012, the Partnership received net cash distributions of approximately $4,000 and $0.2 million, respectively.
NOTE 7 – 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):
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Asset retirement obligations, beginning of year | $ | 64,794 | $ | 45,779 | ||||
Liabilities incurred | 645 | 181 | ||||||
Liabilities settled | (7 | ) | (118 | ) | ||||
Accretion expense | 954 | 696 | ||||||
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Asset retirement obligations, end of period | $ | 66,386 | $ | 46,538 | ||||
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The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Partnership’s consolidated balance sheets.
NOTE 8 – DEBT
Total debt consists of the following at the dates indicated (in thousands):
March 31, 2013 | December 31, 2012 | |||||||
Revolving credit facility | $ | 10,000 | $ | 9,000 | ||||
ARP revolving credit facility | 145,000 | 276,000 | ||||||
ARP term loan | — | 75,425 | ||||||
ARP 7.75 % Senior Notes – due 2021 | 275,000 | — | ||||||
APL revolving credit facility | 154,500 | 293,000 | ||||||
APL 8.75 % Senior Notes – due 2018 | — | 370,184 | ||||||
APL 6.625 % Senior Notes – due 2020 | 505,063 | 505,231 | ||||||
APL 5.875 % Senior Notes – due 2023 | 650,000 | — | ||||||
APL capital leases | 9,349 | 11,503 | ||||||
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Total debt | 1,748,912 | 1,540,343 | ||||||
Less current maturities | (8,861 | ) | (10,835 | ) | ||||
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Total long-term debt | $ | 1,740,051 | $ | 1,529,508 | ||||
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Partnership’s Credit Facility
In May 2012, the Partnership entered into a credit facility with a syndicate of banks that matures in May 2016. On March 1, 2013, the Partnership amended its credit facility to increase its maximum lender commitments to $100.0 million, of which up to $5.0 million of the credit facility may be in the form of standby letters of credit. At March 31, 2013, $10.0 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 statement of operations. At March 31, 2013, 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 agreement, its ratio of Total Funded Debt to EBITDA was 0.2 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 153.6 to 1.0 at March 31, 2013.
At March 31, 2013, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.
ARP’s Credit Facility and Term Loan
At March 31, 2013, ARP had a senior secured revolving credit facility with a syndicate of banks with a borrowing base of $368.8 million with $145.0 million outstanding, which is scheduled to mature in March 2016. In January 2013, ARP repaid in full its $75.4 million term loan, which was scheduled to mature in May 2014, with proceeds from its issuance of 7.75% ARP Senior Notes. 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 March 31, 2013. ARP’s obligations under the facility are secured by mortgages on
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its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by substantially all of ARP’s subsidiaries. Borrowings under the credit facility bear interest, at ARP’s election, 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. ARP is also required to pay a fee of 0.5% per annum on the unused portion of the borrowing base, which is included within interest expense on the Partnership’s consolidated statements of operations. At March 31, 2013, the weighted average interest rate was 2.5%.
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 March 31, 2013. 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 agreement, its ratio of current assets to current liabilities was 1.8 to 1.0, its ratio of Total Funded Debt to EBITDA was 3.6 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 25.8 to 1.0 at March 31, 2013.
ARP Senior Notes
On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes in a private placement transaction at par. ARP used the net proceeds of approximately $267.9 million, net of underwriting fees and other offering costs of $7.1 million, to repay all of the indebtedness and accrued interest outstanding under its term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. 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. 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. 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 governing 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. ARP was in compliance with these covenants as of March 31, 2013.
In connection with the issuance of the 7.75% ARP Senior Notes, ARP 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 January 23, 2014. If ARP does not meet the aforementioned deadline, the 7.75% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that ARP causes the exchange offer to be consummated.
APL Credit Facility
At March 31, 2013, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $154.5 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.00%, 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 March 31, 2013 was 2.5%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at March 31, 2013. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet at March 31, 2013. At March 31, 2013, APL had $445.4 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.
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Borrowings under APL’s credit facility are secured by (i) 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 and West TX entities in which APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) 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 under 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 March 31, 2013.
APL Senior Notes
At March 31, 2013, APL had $500.0 million principal outstanding of 6.625% APL Senior Notes and $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes” and with the 6.625% APL Senior Notes collectively, the “APL Senior Notes”).
The 6.625% APL Senior Notes were presented combined with a net $5.1 million unamortized premium as of March 31, 2013. Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% APL 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 connection with the issuance of the 6.625% APL Senior Notes, 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 6.625% APL Senior Notes for registered notes, and (b) cause the exchange offer to be consummated by September 23, 2013 in the case of the 6.625% APL Senior Notes issued in September 2012, or by December 15, 2013, in the case of the 6.625% APL Senior Notes issued in December 2012. If APL does not meet the aforementioned deadlines, the 6.625% APL Senior Notes will be subject to additional interest, up to 1% per annum, until such time that APL causes the exchange offer to be consummated. On April 12, 2013, APL filed an amendment to its 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 April 12, 2013.
On February 11, 2013, APL issued $650.0 million of 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 $637.1 million after underwriting commissions and other transaction costs and utilized the proceeds to redeem the 8.75% APL Senior Notes and repay a portion of its outstanding indebtedness under its revolving credit facility. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.
In connection with the issuance of the 5.875% APL Senior Notes, 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 5.875% APL Senior Notes for registered notes, and (b) cause the exchange offer to be consummated by February 6, 2014. If APL does not meet the aforementioned deadline, the 5.875% APL Senior Notes will be subject to additional interest, up to 1% per annum, until such time that APL causes the exchange offer to be consummated.
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 (“8.75% APL Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% APL Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million premium, $3.7 million accrued interest and $8.0 million consent payment. APL entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture. APL also issued a notice to redeem all the 8.75% APL Senior Notes not purchased in connection with the tender offer.
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On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% APL Senior Notes plus a $6.3 million premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes. For the three months ended March 31, 2013, APL recognized a loss of $26.6 million within loss on early extinguishment of debt on the Partnership’s consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid, $8.0 million consent payment and a $5.3 millionwrite-off of deferred financing costs (see Note 6), partially offset by $4.2 million of unamortized premium recognized.
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 on 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 March 31, 2013.
APL Capital Leases
The following is a summary of the leased property under capital leases as of March 31, 2013 and December 31, 2012, which are included within property, plant and equipment (see Note 5) (in thousands):
March 31, 2013 | December 31, 2012 | |||||||
Pipelines, processing and compression facilities | $ | 15,457 | $ | 15,457 | ||||
Less – accumulated depreciation | (1,277 | ) | (1,066 | ) | ||||
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$ | 14,180 | $ | 14,391 | |||||
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Depreciation expense for leased properties was $0.2 million for the three months ended March 31, 2013 and 2012. Depreciation expense for leased properties is included within depreciation and amortization expense on the Partnership’s consolidated statements of operations.
Cash payments for interest by the Partnership and its subsidiaries were $26.7 million and $1.4 million for the three months ended March 31, 2013 and 2012, respectively.
NOTE 9 – 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.
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 are determined by management of ARP and APL through the utilization of market data, will be recognized immediately within gain (loss) on
25
mark-to-market derivatives in the Partnership’s consolidated 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 (loss) 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 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 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 $11.5 million and $51.3 million at March 31, 2013 and December 31, 2012, respectively. Of the $2.0 million of net loss in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at March 31, 2013, if the fair values of the instruments remain at current market values, the Partnership will reclassify $3.9 million of losses to gas and oil production revenue on its consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $1.9 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated 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. No amounts were reclassified from other comprehensive income (loss) related to derivative instruments entered into during the three months ended March 31, 2013.
The following table summarizes ARP’s and APL’s gain or loss recognized in the Partnership’s consolidated statements of operations for effective derivative instruments, excluding the effect of non-controlling interest, for the periods indicated (in thousands):
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
(Gain) loss reclassified from accumulated other comprehensive income (loss): | ||||||||
Gas and oil production revenue | $ | (993 | ) | $ | (2,600 | ) | ||
Gathering and processing revenue | — | 1,146 | ||||||
|
|
|
| |||||
Total | $ | (993 | ) | $ | (1,454 | ) | ||
|
|
|
|
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):
26
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 March 31, 2013 | ||||||||||||
Current portion of derivative assets | $ | 3,231 | $ | (1,462 | ) | $ | 1,769 | |||||
Long-term portion of derivative assets | 6,421 | (2,216 | ) | 4,205 | ||||||||
Current portion of derivative liabilities | 3,172 | (3,172 | ) | — | ||||||||
Long-term portion of derivative liabilities | 7,271 | (7,271 | ) | — | ||||||||
|
|
|
|
|
| |||||||
Total derivative assets | $ | 20,095 | $ | (14,121 | ) | $ | 5,974 | |||||
|
|
|
|
|
| |||||||
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 | |||||
|
|
|
|
|
| |||||||
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 March 31, 2013 | ||||||||||||
Current portion of derivative assets | $ | (1,462 | ) | $ | 1,462 | $ | — | |||||
Long-term portion of derivative assets | (2,216 | ) | 2,216 | — | ||||||||
Current portion of derivative liabilities | (13,180 | ) | 3,172 | (10,008 | ) | |||||||
Long-term portion of derivative liabilities | (9,963 | ) | 7,271 | (2,692 | ) | |||||||
|
|
|
|
|
| |||||||
Total derivative liabilities | $ | (26,821 | ) | $ | 14,121 | $ | (12,700 | ) | ||||
|
|
|
|
|
| |||||||
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 | ) | ||||
|
|
|
|
|
|
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 8). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income (loss) 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 3). 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 three months ended March 31, 2012, ARP recorded $1.0 million of amortization expense in other, net on the Partnership’s consolidated statements of operations related to the swaption contracts.
ARP recognized gains of $1.0 million and $2.6 million for the three months ended March 31, 2013 and 2012, respectively, on settled contracts covering commodity production. These gains and losses were included within gas and oil production revenue in the Partnership’s consolidated 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 three months ended March 31, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
27
At March 31, 2013, ARP had the following commodity derivatives:
Natural Gas Fixed Price Swaps
Production | Volumes | Average Fixed Price | Fair Value Asset/(Liability) | |||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||
2013 | 21,532,300 | $ | 3.823 | $ | (6,470 | ) | ||||||||
2014 | 30,153,000 | $ | 4.142 | (2,708 | ) | |||||||||
2015 | 22,314,500 | $ | 4.243 | (1,370 | ) | |||||||||
2016 | 17,906,300 | $ | 4.391 | 113 | ||||||||||
2017 | 11,400,000 | $ | 4.620 | 1,067 | ||||||||||
|
| |||||||||||||
$ | (9,368 | ) | ||||||||||||
|
|
Natural Gas Costless Collars
Production | Option Type | Volumes | Average Floor and Cap | Fair Value Asset/(Liability) | ||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||
2013 | Puts purchased | 4,140,000 | $ | 4.395 | $ | 2,019 | ||||||||
2013 | Calls sold | 4,140,000 | $ | 5.443 | (222 | ) | ||||||||
2014 | Puts purchased | 3,840,000 | $ | 4.221 | 1,871 | |||||||||
2014 | Calls sold | 3,840,000 | $ | 5.120 | (882 | ) | ||||||||
2015 | Puts purchased | 3,480,000 | $ | 4.234 | 1,953 | |||||||||
2015 | Calls sold | 3,480,000 | $ | 5.129 | (1,201 | ) | ||||||||
|
| |||||||||||||
$ | 3,538 | |||||||||||||
|
|
Natural Gas Put Options
Production | Option Type | Volumes | Average Fixed Price | Fair Value Asset | ||||||||||
(MMBtu)(1) | (per MMBtu)(1) | (in thousands)(2) | ||||||||||||
2013 | Puts purchased | 2,130,000 | $ | 3.450 | $ | 75 | ||||||||
2014 | Puts purchased | 1,800,000 | $ | 3.800 | 473 | |||||||||
2015 | Puts purchased | 1,440,000 | $ | 4.000 | 592 | |||||||||
2016 | Puts purchased | 1,440,000 | $ | 4.150 | 792 | |||||||||
|
| |||||||||||||
$ | 1,932 | |||||||||||||
|
|
Natural Gas Liquids Fixed Price Swaps
Production | Volumes | Average Fixed Price | Fair Value Liability | |||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||
2013 | 137,500 | $ | 92.694 | $ | (508 | ) | ||||||||
2014 | 123,000 | $ | 91.414 | (179 | ) | |||||||||
2015 | 96,000 | $ | 88.550 | (74 | ) | |||||||||
2016 | 60,000 | $ | 85.920 | (62 | ) | |||||||||
|
| |||||||||||||
$ | (823 | ) | ||||||||||||
|
|
28
Crude Oil Fixed Price Swaps
Production | Volumes | Average Fixed Price | Fair Value Liability | |||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||
2013 | 322,000 | $ | 92.476 | $ | (1,281 | ) | ||||||||
2014 | 396,000 | $ | 91.783 | (383 | ) | |||||||||
2015 | 411,000 | $ | 88.030 | (521 | ) | |||||||||
2016 | 129,000 | $ | 86.211 | (97 | ) | |||||||||
2017 | 36,000 | $ | 84.600 | (28 | ) | |||||||||
|
| |||||||||||||
$ | (2,310 | ) | ||||||||||||
|
|
Crude Oil Costless Collars
Production | Option Type | Volumes | Average Floor and Cap | Fair Value Asset/(Liability) | ||||||||||
(Bbl)(1) | (per Bbl)(1) | (in thousands)(3) | ||||||||||||
2013 | Puts purchased | 50,000 | $ | 90.000 | $ | 99 | ||||||||
2013 | Calls sold | 50,000 | $ | 116.396 | (18 | ) | ||||||||
2014 | Puts purchased | 41,160 | $ | 84.169 | 203 | |||||||||
2014 | Calls sold | 41,160 | $ | 113.308 | (88 | ) | ||||||||
2015 | Puts purchased | 29,250 | $ | 83.846 | 213 | |||||||||
2015 | Calls sold | 29,250 | $ | 110.654 | (104 | ) | ||||||||
|
| |||||||||||||
$ | 305 | |||||||||||||
|
| |||||||||||||
Total ARP net liabilities | $ | (6,726 | ) | |||||||||||
|
|
(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. |
At March 31, 2013, ARP had net cash proceeds of $7.4 million related to ARP’s hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s consolidated balance sheet. 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 March 31, 2013 and December 31, 2012.
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 March 31, 2013, net unrealized derivative assets of $1.9 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 March 31, 2013 and December 31, 2012 were included in the Partnership’s consolidated balance sheets as follows (in thousands):
March 31, 2013 | December 31, 2012 | |||||||
Current portion of derivative payable to Drilling Partnerships: | ||||||||
Hedge monetization proceeds | $ | (8,513 | ) | $ | (10,748 | ) | ||
Hedge contracts covering future natural gas production | (152 | ) | (545 | ) | ||||
Long-term portion of derivative payable to Drilling Partnerships: | ||||||||
Hedge monetization proceeds | 1,106 | (205 | ) | |||||
Hedge contracts covering future natural gas production | (1,776 | ) | (2,224 | ) | ||||
|
|
|
| |||||
$ | (9,335 | ) | $ | (13,722 | ) | |||
|
|
|
|
At March 31, 2013, 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 8), ARP is required to utilize this secured hedge facility for future 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
29
Partnership. 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
APL has elected not to apply hedge accounting for derivative contracts entered into in July 2008 and after. Changes in the fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated 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 (loss) on the Partnership’s consolidated balance sheets to gathering and processing revenue on the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. During the three months ended March 31, 2012, APL reclassified $1.1 million of losses out of other comprehensive income (loss) related to derivative contracts entered into prior to July 2008. As of December 31, 2012, all amounts had been reclassified out of other comprehensive income (loss) and APL had no amounts outstanding within other comprehensive income (loss).
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 Derivative Assets | ||||||||||||
As of March 31, 2013 | ||||||||||||
Current portion of derivative assets | $ | 19,872 | $ | (2,481 | ) | $ | 17,391 | |||||
Long-term portion of derivative assets | 4,570 | (2,192 | ) | 2,378 | ||||||||
Long-term portion of derivative liabilities | 3,248 | (3,248 | ) | — | ||||||||
|
|
|
|
|
| |||||||
Total derivative assets | $ | 27,690 | $ | (7,921 | ) | $ | 19,769 | |||||
|
|
|
|
|
| |||||||
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 | |||||
|
|
|
|
|
| |||||||
Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts of Liabilities Presented in the Consolidated Balance Sheets | ||||||||||
Offsetting Derivative Liabilities | ||||||||||||
As of March 31, 2013 | ||||||||||||
Current portion of derivative assets | $ | (2,481 | ) | $ | 2,481 | $ | — | |||||
Long-term portion of derivative assets | (2,192 | ) | 2,192 | — | ||||||||
Current portion of derivative liabilities | (619 | ) | — | (619 | ) | |||||||
Long-term portion of derivative liabilities | (4,173 | ) | 3,248 | (925 | ) | |||||||
|
|
|
|
|
| |||||||
Total derivative liabilities | $ | (9,465 | ) | $ | 7,921 | $ | (1,544 | ) | ||||
|
|
|
|
|
| |||||||
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 | $ | — | |||||
|
|
|
|
|
|
30
As of March 31, 2013, APL had the following commodity derivatives:
Fixed Price Swaps
Production Period | Purchased/ Sold | Commodity | Volumes(2) | Average Fixed Price | Fair Value(1) Asset/(Liability) (in thousands) | |||||||||||
Natural Gas | ||||||||||||||||
2013 | Sold | Natural Gas | 3,130,000 | $ | 3.607 | $ | (1,692 | ) | ||||||||
2014 | Sold | Natural Gas | 12,000,000 | $ | 3.963 | (3,065 | ) | |||||||||
2015 | Sold | Natural Gas | 12,100,000 | $ | 4.212 | (1,091 | ) | |||||||||
2016 | Sold | Natural Gas | 1,200,000 | $ | 4.403 | 23 | ||||||||||
Natural Gas Liquids | ||||||||||||||||
2013 | Sold | Natural Gas Liquids | 41,454,000 | $ | 1.267 | 11,727 | ||||||||||
2014 | Sold | Natural Gas Liquids | 46,746,000 | $ | 1.220 | 1,177 | ||||||||||
2015 | Sold | Natural Gas Liquids | 23,688,000 | $ | 1.110 | (1,111 | ) | |||||||||
Crude Oil | ||||||||||||||||
2013 | Sold | Crude Oil | 252,000 | $ | 97.053 | 32 | ||||||||||
2014 | Sold | Crude Oil | 303,000 | $ | 92.383 | (222 | ) | |||||||||
|
| |||||||||||||||
Total Fixed Price Swaps | $ | 5,778 | ||||||||||||||
|
|
Options
Production | Purchased/ Sold | Type | Commodity | Volumes(2) | Average Strike Price | Fair Value(1) Asset (in thousands) | ||||||||||||
Natural Gas | ||||||||||||||||||
2013 | Purchased | Put | Natural Gas | 600,000 | $ | 4.125 | $ | 270 | ||||||||||
Natural Gas Liquids | ||||||||||||||||||
2013 | Purchased | Put | Natural Gas Liquids | 32,508,000 | $ | 1.879 | 4,712 | |||||||||||
Crude Oil | ||||||||||||||||||
2013 | Purchased | Put | Crude Oil | �� | 216,000 | $ | 100.100 | 1,287 | ||||||||||
2014 | Purchased | Put | Crude Oil | 388,500 | $ | 95.239 | 3,517 | |||||||||||
2015 | Purchased | Put | Crude Oil | 270,000 | $ | 89.175 | 2,661 | |||||||||||
|
| |||||||||||||||||
Total Options | $ | 12,447 | ||||||||||||||||
|
| |||||||||||||||||
Total APL net asset | $ | 18,225 | ||||||||||||||||
|
|
(1) | See Note 10 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 APL’s derivatives not designated as hedges, which are included within loss on mark-to market derivatives on the Partnerships consolidated statement of operations:
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Gain (loss) recognized in loss on mark-to-market derivatives: | ||||||||
Commodity contract – realized(1) | $ | 1,636 | $ | (763 | ) | |||
Commodity contract – unrealized(2) | (13,719 | ) | (11,272 | ) | ||||
|
|
|
| |||||
Loss on mark-to-market derivatives | $ | (12,083 | ) | $ | (12,035 | ) | ||
|
|
|
|
31
(1) | Realized loss represents the loss incurred when the derivative contract expires and/or is cash settled. |
(2) | Unrealized loss represents the mark-to-market loss recognized on open derivative contracts, which have not yet been settled. |
The fair value of the derivatives included in the Partnership’s consolidated balance sheets for the periods indicated was as follows (in thousands):
March 31, 2013 | December 31, 2012 | |||||||
Current portion of derivative asset | $ | 19,160 | $ | 35,351 | ||||
Long-term derivative asset | 6,583 | 16,840 | ||||||
Current portion of derivative liability | (10,627 | ) | — | |||||
Long-term derivative liability | (3,617 | ) | (888 | ) | ||||
|
|
|
| |||||
Total Partnership net asset | $ | 11,499 | $ | 51,303 | ||||
|
|
|
|
NOTE 10 – 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 9). 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 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.
32
Information for ARP’s and APL’s assets and liabilities measured at fair value at March 31, 2013 and December 31, 2012 was as follows (in thousands):
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
As of March 31, 2013 | ||||||||||||||||
Derivative assets, gross | ||||||||||||||||
ARP Commodity swaps | $ | — | $ | 11,807 | $ | — | $ | 11,807 | ||||||||
ARP Commodity puts | — | 1,931 | — | 1,931 | ||||||||||||
ARP Commodity options | — | 6,357 | — | 6,357 | ||||||||||||
APL Commodity swaps | — | 1,141 | 14,102 | 15,243 | ||||||||||||
APL Commodity options | — | 7,735 | 4,712 | 12,447 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total derivative assets, gross | — | 28,971 | 18,814 | 47,785 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Derivative liabilities, gross | ||||||||||||||||
ARP Commodity swaps | — | (24,307 | ) | — | (24,307 | ) | ||||||||||
ARP Commodity puts | — | — | — | — | ||||||||||||
ARP Commodity options | — | (2,514 | ) | — | (2,514 | ) | ||||||||||
APL Commodity swaps | — | (7,156 | ) | (2,309 | ) | (9,465 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total derivative liabilities, gross | — | (33,977 | ) | (2,309 | ) | (36,286 | ) | |||||||||
|
|
|
|
|
|
|
| |||||||||
Total derivatives, fair value, net | $ | — | $ | (5,006 | ) | $ | 16,505 | $ | 11,499 | |||||||
|
|
|
|
|
|
|
| |||||||||
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 | ||||||||||||
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| |||||||||
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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|
|
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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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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, 2013 | 87,066 | $ | 16,814 | 38,556 | $ | 6,269 | $ | 23,083 | ||||||||||||
New contracts(2) | 39,312 | — | 1,260 | 88 | 88 | |||||||||||||||
Cash settlements from unrealized gain (loss)(3)(4) | (14,490 | ) | (3,888 | ) | (7,308 | ) | 2,044 | (1,844 | ) | |||||||||||
Net change in unrealized loss(3) | — | (1,133 | ) | — | (1,290 | ) | (2,423 | ) | ||||||||||||
Option premium recognition(4) | — | — | — | (2,399 | ) | (2,399 | ) | |||||||||||||
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|
|
|
|
|
|
|
| |||||||||||
Balance – March 31, 2013 | 111,888 | $ | 11,793 | 32,508 | $ | 4,712 | $ | 16,505 | ||||||||||||
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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 loss on mark-to-market derivatives on the Partnership’s consolidated statements of operations. |
(4) | Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration. |
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The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at March 31, 2013 and December 31, 2012 (in thousands):
Gallons | Third Party Quotes(1) | Adjustments(2) | Total Amount | |||||||||||||
As of March 31, 2013 | ||||||||||||||||
Propane swaps | 92,736 | $ | 9,906 | $ | (319 | ) | $ | 9,587 | ||||||||
Isobutane swaps | 630 | 48 | 78 | 126 | ||||||||||||
Normal butane swaps | 5,040 | 233 | 134 | 367 | ||||||||||||
Natural gasoline swaps | 13,482 | 3,978 | (2,265 | ) | 1,713 | |||||||||||
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|
|
|
|
|
| |||||||||
Total NGL swaps – March 31, 2013 | 111,888 | $ | 14,165 | $ | (2,372 | ) | $ | 11,793 | ||||||||
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|
|
|
| |||||||||
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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(1) | Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap. |
(2) | Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three year historical period. |
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 fixed price swaps for the periods indicated (in thousands):
Adjustment based upon Regression Coefficient | ||||||||||||||||
Level 3 Fair Value Adjustments | Lower 95% | Upper 95% | Average Coefficient | |||||||||||||
As of March 31, 2013 | ||||||||||||||||
Propane swaps | $ | (319 | ) | 0.8969 | 0.9069 | 0.9019 | ||||||||||
Isobutane swaps | 78 | 1.1274 | 1.1366 | 1.1320 | ||||||||||||
Normal butane swaps | 134 | 1.0384 | 1.0430 | 1.0407 | ||||||||||||
Natural gasoline swaps | (2,265 | ) | 0.9063 | 0.9251 | 0.9157 | |||||||||||
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Total NGL swaps – March 31, 2013 | $ | (2,372 | ) | |||||||||||||
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| |||||||||||||||
As of December 31, 2012 | ||||||||||||||||
Propane swaps | $ | (552 | ) | 0.9019 | 0.9122 | 0.9071 | ||||||||||
Isobutane swaps | 187 | 1.1285 | 1.1376 | 1.1331 | ||||||||||||
Normal butane swaps | 242 | 1.0370 | 1.0416 | 1.0393 | ||||||||||||
Natural gasoline swaps | (1,484 | ) | 0.8988 | 0.9169 | 0.9078 | |||||||||||
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Total NGL swaps – December 31, 2012 | $ | (1,607 | ) | |||||||||||||
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APL had $7.8 million of NGL linefill at both March 31, 2013 and December 31, 2012, 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 as of March 31, 2013 and December 31, 2012.
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The following table provides a summary of changes in fair value of APL’s NGL linefill for the three months ended March 31, 2013 (in thousands):
NGL Linefill | ||||||||
Gallons | Amount | |||||||
Balance – January 1, 2013 | 9,148 | $ | 7,783 | |||||
Net change in NGL linefill valuation(1) | — | (32 | ) | |||||
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| |||||
Balance – March 31, 2013 | 9,148 | $ | 7,751 | |||||
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(1) | Included within gathering and processing revenues on the Partnership’s consolidated statements of operations. |
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 March 31, 2013 and December 31, 2012, which consist principally of ARP’s and APL’s senior notes and borrowings under ARP’s and APL’s revolving and term loan credit facilities, were $1,750.0 million and $1,576.9 million, respectively, compared with the carrying amounts of $1,748.9 million and $1,540.3 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP and APL senior notes were based upon the market approach and calculated using the yields of the ARP and APL senior notes as provided by financial institutions and thus were categorized as a Level 3 value.
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 7). Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2013 and 2012 was as follows (in thousands):
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Level 3 | Total | Level 3 | Total | |||||||||||||
Asset retirement obligations | $ | 645 | $ | 645 | $ | 181 | $ | 181 | ||||||||
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Total | $ | 645 | $ | 645 | $ | 181 | $ | 181 | ||||||||
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|
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”). Sufficient volumes were achieved in December 2012, and APL paid the first Trigger Payment of $6.0 million in January 2013. As of March 31, 2013, the fair value of the remaining Trigger Payment resulted in a $6.0 million long-term liability, which was recorded within other long-term liabilities on the Partnership’s consolidated balance sheets. The range of the undiscounted amounts APL could pay related to the remaining Trigger Payment is up to $6.0 million.
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NOTE 11 – INCOME TAXES
In connection with the Cardinal Acquisition (see Note 3), APL acquired a taxable subsidiary in December 2012. The components of the federal and state income tax benefit for APL’s taxable subsidiary at March 31, 2013 are as follows (in thousands):
Three Months Ended March 31, 2013 | ||||
Deferred benefit: | ||||
Federal | $ | 8 | ||
State | 1 | |||
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| |||
Total income tax benefit | $ | 9 | ||
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|
As of March 31, 2013 and December 31, 2012, APL had non-current net deferred income tax liabilities of $30.2 million and $30.3 million, respectively. The components of net deferred tax liabilities as of March 31, 2013 and December 31, 2012 consist of the following (in thousands):
March 31, 2013 | December 31, 2012 | |||||||
Deferred tax assets: | ||||||||
Net operating loss tax carryforwards and alternative minimum tax credits | $ | 10,864 | $ | 10,277 | ||||
Deferred tax liabilities: | ||||||||
Excess of asset carrying value over tax basis | (41,113 | ) | (40,535 | ) | ||||
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|
| |||||
Net deferred tax liabilities | $ | (30,249 | ) | $ | (30,258 | ) | ||
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As of March 31, 2013, APL had net operating loss carry forwards for federal income tax purposes of approximately $27.9 million, which expire at various dates from 2029 to 2032. APL believes it more likely than not that the deferred tax asset will be fully utilized.
NOTE 12 – 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 of the Drilling Partnerships 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 each of the three month periods ended March 31, 2013 and 2012, $0.1 million of gathering fees paid by ARP to APL were eliminated in consolidation.
NOTE 13 – COMMITMENTS AND CONTINGENCIES
General Commitments
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, as of March 31, 2013, the management of ARP believes that any such 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 three months ended March 31, 2013 and 2012, $2.1 million and $0.4 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.
36
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.
APL has certain long-term unconditional purchase obligations and commitments, primarily transportation 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 $3.0 million and $2.5 million for the three months ended March 31, 2013 and 2012, respectively. The future fixed and determinable portions of APL’s obligations as of March 31, 2013 were as follows: 2013 - $7.0 million; 2014 - $9.5 million; and 2015-2017 - $3.5 million per year.
As of March 31, 2013, ARP and APL are committed to expend approximately $80.6 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.
Legal Proceedings
On August 3, 2011, CNX Gas Company LLC (“CNX”) 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 Resources, Inc. (“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 14 – 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 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.
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, the Partnership 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.
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 3). 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
37
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 3). 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
APL has an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL may offer and sell from time to time through Citigroup, as its sales agent, common units having an aggregate value of up to $150.0 million. Subject to the terms and conditions of the equity distribution agreement, Citigroup will not be 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. Such sales will be at market prices prevailing at the time of the sale. There will be no specific date on which the offering will end; there will be no minimum purchase requirements; and there will be no arrangements to place the proceeds of the offering in an escrow, trust or similar account. Under the terms of the equity distribution agreement, APL also may sell common units to Citigroup as principal for its own account at a price agreed upon at the time of the sale. APL intends to use the net proceeds from any such offering for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. During the three months ended March 31, 2013, APL issued 447,785 common units under the equity distribution program for net proceeds of $14.1 million, net of $0.3 million in commission paid to Citigroup. APL also received a capital contribution from the Partnership of $0.3 million to maintain its 2.0% general partner interest in APL. The net proceeds from the common unit offering were utilized for general partnership purposes.
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
38
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 3).
NOTE 15 – CASH DISTRIBUTIONS
The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2012 through March 31, 2013 were as follows (in thousands, except per unit amounts):
Date Cash | For Quarter Ended | Cash Distribution per Common Limited Partner Unit | Total Cash Distributions Paid to Common Limited Partners | |||||||
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 | |||||
February 19, 2013 | December 31, 2012 | $ | 0.30 | $ | 15,410 |
On April 25, 2013, the Partnership declared a cash distribution of $0.31 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $15.9 million distribution will be paid on May 20, 2013 to unitholders of record at the close of business on May 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.
Distributions declared by ARP from its formation through March 31, 2013 were as follows (in thousands, except per unit amounts):
Date Cash | For Quarter Ended | Cash Distribution per Common Limited Partner Unit | Total Cash Distribution to Common Limited Partners | Total Cash Distribution To Preferred Limited Partners | Total Cash Distribution to the General Partner | |||||||||||||
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 | |||||||||
February 14, 2013 | December 31, 2012 | $ | 0.48 | $ | 21,107 | $ | 1,841 | $ | 618 |
(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 April 25, 2013, ARP declared a cash distribution of $0.51 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $25.3 million distribution, including $0.9 million to the Partnership as general partner, and $2.0 million to its preferred limited partners, will be paid on May 15, 2013 to unitholders of record at the close of business on May 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, 2012 through March 31, 2013 were as follows (in thousands, except per unit amounts):
39
Date Cash | For Quarter Ended | APL Cash Distribution per Common Limited Partner Unit | Total APL Cash Distribution to Common Limited Partners | Total APL Cash Distribution to the General Partner | ||||||||||
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 | |||||||
February 14, 2013 | December 31, 2012 | $ | 0.58 | $ | 37,442 | $ | 3,117 |
On April 24, 2013, APL declared a cash distribution of $0.59 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $49.3 million distribution, including $4.0 million to the Partnership as general partner, will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013.
NOTE 16 – BENEFIT PLANS
2010 Long-Term Incentive Plan
The Board of Directors of the General Partner approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the 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 March 31, 2013, the Partnership had 4,543,390 phantom units and unit options outstanding under the 2010 LTIP, with 1,192,340 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. |
40
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. Generally, phantom units granted under the 2010 LTIP will vest over a three or four year period from the date of grant. Of the phantom units outstanding under the 2010 LTIP at March 31, 2013, there are 413,806 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at March 31, 2013 include DERs. During the three months ended March 31, 2013 and 2012, the Partnership paid $0.6 million and $0.4 million, respectively, with respect to the 2010 LTIP DERs.
The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of year | 2,044,227 | $ | 20.90 | 1,838,164 | $ | 22.11 | ||||||||||
Granted | — | — | 55,300 | 26.66 | ||||||||||||
Vested(1) | (2,936 | ) | 17.47 | (7,226 | ) | 20.67 | ||||||||||
Forfeited | — | — | — | — | ||||||||||||
ARP anti-dilution adjustment(2) | — | — | 165,468 | — | ||||||||||||
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|
|
|
|
|
|
| |||||||||
Outstanding, end of period(3) | 2,041,291 | $ | 20.91 | 2,051,706 | $ | 20.46 | ||||||||||
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|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) | $ | 3,108 | $ | 3,002 | ||||||||||||
|
|
|
|
(1) | The aggregate intrinsic values of phantom unit awards vested during the three months ended March 31, 2013 and 2012 were $0.1 million and $0.2 million, respectively. |
(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 March 31, 2013 was $89.9 million. |
At March 31, 2013, the Partnership had approximately $21.3 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 determines 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. Generally, unit options granted under the 2010 LTIP generally will vest over a three or four year period from the date of grant. There are 573,323 unit options outstanding under the 2010 LTIP at March 31, 2013 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2013 and 2012.
The following table sets forth the 2010 LTIP unit option activity for the periods indicated:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||
Outstanding, beginning of year | 2,504,703 | $ | 20.51 | 2,304,300 | $ | 22.12 | ||||||||||
Granted | — | — | 69,229 | 26.27 | ||||||||||||
Exercised(1) | — | — | — | — | ||||||||||||
Forfeited | (2,604 | ) | 17.47 | — | — | |||||||||||
ARP anti-dilution adjustment(2) | — | — | 207,793 | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(3)(4) | 2,502,099 | $ | 20.52 | 2,581,322 | $ | 20.45 | ||||||||||
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|
|
|
|
| |||||||||
Options exercisable, end of period(5) | 3,398 | $ | 20.85 | — | $ | — | ||||||||||
|
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|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,515 | $ | 1,561 | ||||||||||||
|
|
|
|
41
(1) | No options were exercised during the three months ended March 31, 2013 and 2012. |
(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 March 31, 2013 was 8.0 years. |
(4) | The options outstanding at March 31, 2013 had an aggregate intrinsic value of $58.8 million. |
(5) | The weighted average remaining contractual life for exercisable options at March 31, 2013 was 8.4 years. The intrinsic value of exercisable options at March 31, 2013 was $0.1 million. No options were exercisable at March 31, 2012. |
At March 31, 2013, the Partnership had approximately $10.4 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:
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Expected dividend yield | — | 3.7% | ||||||
Expected unit price volatility | — | 47.0% | ||||||
Risk-free interest rate | — | 1.4% | ||||||
Expected term (in years) | — | 6.88 | ||||||
Fair value of unit options granted | — | $8.50 |
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 March 31, 2013, the Partnership had 1,189,975 phantom units and unit options outstanding under the 2006 LTIP, with 763,062 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. Generally, phantom units granted to employees under the 2006 LTIP will vest over a three or four year period 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 March 31, 2013, 80,448 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at March 31, 2013 include DERs. During the three months ended March 31, 2013 and 2012, respectively, the Partnership paid approximately $73,000 and $8,000 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:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of year | 50,759 | $ | 21.02 | 32,641 | $ | 15.99 | ||||||||||
Granted | 204,777 | 37.92 | 7,688 | 26.01 | ||||||||||||
Vested(1)(2) | (5,500 | ) | 18.16 | (6,253 | ) | 24.06 | ||||||||||
Forfeited | — | — | — | — | ||||||||||||
ARP anti-dilution adjustment(3) | — | — | 2,977 | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Outstanding, end of period(4)(5) | 250,036 | $ | 34.92 | 37,053 | $ | 15.42 | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,147 | $ | 167 | ||||||||||||
|
|
|
|
42
(1) | The intrinsic value for phantom unit awards vested during the three months ended March 31, 2013 and 2012 was $0.2 million. |
(2) | There were 522 vested units during the three months ended March 31, 2013 that were settled for approximately $20,000 cash. No units were settled in cash during the three months ended March 31, 2012. |
(3) | The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units. |
(4) | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2013 was $11.0 million. |
(5) | There was $0.8 million, $0.7 million and $0.9 million recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2013, December 31, 2012 and March 31, 2012, respectively, representing 51,990, 44,234 and 30,528 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units are $27.47, $23.25 and $17.45 as of March 31, 2013, December 31, 2012 and March 31, 2012, respectively. |
At March 31, 2013, the Partnership had approximately $8.0 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. Generally, unit options granted under the 2006 LTIP will vest over a three or four year period from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the 2006 LTIP. There are 2,500 unit options outstanding under the 2006 LTIP at March 31, 2013 that will vest within the following twelve months. For the three months ended March 31, 2012, the Partnership received cash of approximately $32,000 from the exercise of options. No cash was received from the exercise of options during the three months ended March 31, 2013.
The following table sets forth the 2006 LTIP unit option activity for the periods indicated:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||
Outstanding, beginning of year | 929,939 | $ | 20.75 | 903,614 | $ | 21.52 | ||||||||||
Granted | 10,000 | 38.51 | — | — | ||||||||||||
Exercised(1) | — | — | (15,438 | ) | 3.24 | |||||||||||
Forfeited | — | — | — | — | ||||||||||||
ARP anti-dilution adjustment(2) | — | — | 78,323 | — | ||||||||||||
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|
|
|
|
|
|
| |||||||||
Outstanding, end of period(3)(4) | 939,939 | $ | 20.94 | 966,499 | $ | 20.08 | ||||||||||
|
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|
|
|
|
| |||||||||
Options exercisable, end of period(5) | 929,939 | $ | 20.75 | 966,499 | $ | 20.08 | ||||||||||
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| |||||||||
Non-cash compensation expense recognized (in thousands) | $ | 7 | $ | — | ||||||||||||
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|
|
|
(1) | The intrinsic value of options exercised during the three months ended March 31, 2012 was $0.4 million. No options were exercised during the three months ended March 31, 2013. |
(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 March 31, 2013 was 3.7 years. |
(4) | The aggregate intrinsic value of options outstanding at March 31, 2013 was approximately $21.7 million. |
(5) | The weighted average remaining contractual lives for exercisable options at March 31, 2013 and 2012 were 3.6 years and 4.7 years, respectively. The aggregate intrinsic values of options exercisable at March 31, 2013 and 2012 were $21.7 million and $12.5 million, respectively. |
At March 31, 2013, the Partnership had $0.1 million of 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.
43
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Expected dividend yield | 3.2 | % | — | |||||
Expected unit price volatility | 30.0 | % | — | |||||
Risk-free interest rate | 0.7 | % | — | |||||
Expected term (in years) | 6.25 | — | ||||||
Fair value of unit options granted | $ | 7.54 | — |
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’s general partner 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 March 31, 2013, ARP had 2,538,761 phantom units, restricted units and unit options outstanding under the ARP LTIP, with 358,774 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.
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. 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 March 31, 2013, 238,806 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at March 31, 2013 include DERs. During the three months ended March 31, 2013, ARP paid $0.5 million with respect to ARP LTIP’s DERs. No amounts were paid during the three months ended March 31, 2012 with respect to DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheet.
44
The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of year | 948,476 | $ | 24.76 | — | $ | — | ||||||||||
Granted | 83,250 | 21.96 | — | — | ||||||||||||
Vested(1) | (2,465 | ) | 24.67 | — | — | |||||||||||
Forfeited | (4,000 | ) | 25.14 | — | — | |||||||||||
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| |||||||||
Outstanding, end of period(2)(3) | 1,025,261 | $ | 24.53 | — | $ | — | ||||||||||
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|
|
| |||||||||
Non-cash compensation expense recognized (in thousands) |
| $ | 3,053 | $ | — | |||||||||||
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|
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(1) | The intrinsic value of phantom unit awards vested during the three months ended March 31, 2013 was $0.1 million. No phantom unit awards vested during the three months ended March 31, 2012. |
(2) | The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2013 was $24.8 million. |
(3) | There was approximately $44,000 and $31,000 recognized as liabilities on the Partnership’s consolidated balance sheets at March 31, 2013 and December 31, 2012, respectively, representing 3,476 and 3,476 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $28.75 and $28.75 at March 31, 2013 and December 31, 2012, respectively. No units were classified within liabilities at March 31, 2012. |
At March 31, 2013, ARP had approximately $14.5 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards.
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. 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 378,375 unit options outstanding under the ARP LTIP at March 31, 2013 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2013 and 2012.
The following table sets forth the ARP LTIP unit option activity for the periods indicated:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Number of Unit Options | Weighted Average Exercise Price | Number of Unit Options | Weighted Average Exercise Price | |||||||||||||
Outstanding, beginning of year | 1,515,500 | $ | 24.68 | — | $ | — | ||||||||||
Granted | 2,000 | 22.27 | — | — | ||||||||||||
Exercised(1) | — | — | — | — | ||||||||||||
Forfeited | (4,000 | ) | 25.14 | — | — | |||||||||||
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| |||||||||
Outstanding, end of period(2)(3) | 1,513,500 | $ | 24.67 | — | $ | — | ||||||||||
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| |||||||||
Options exercisable, end of period(4) | — | $ | — | — | $ | — | ||||||||||
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| |||||||||
Non-cash compensation expense recognized (in thousands) | $ | 1,194 | $ | — | ||||||||||||
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(1) | No options were exercised during the three months ended March 31, 2013 and 2012. |
(2) | The weighted average remaining contractual life for outstanding options at March 31, 2013 was 9.1 years. |
(3) | The aggregate intrinsic value of options outstanding at March 31, 2013 was approximately $3,000. |
(4) | No options were exercisable at March 31, 2013. There was no aggregate intrinsic value of options exercisable at March 31, 2013 or 2012. |
45
At March 31 2013, ARP had approximately $4.8 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:
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Expected dividend yield | 6.6 | % | — | |||||
Expected unit price volatility | 44.0 | % | — | |||||
Risk-free interest rate | 1.1 | % | — | |||||
Expected term (in years) | 6.25 | — | ||||||
Fair value of unit options granted | $ | 4.85 | — |
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 APL LTIPs, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At March 31, 2013, APL had 1,057,083 phantom units outstanding under the APL LTIPs, with 1,517,513 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 financial statements based upon their current fair market value. There were no unit options outstanding as of March 31, 2013.
APL Phantom Units. Through March 31, 2013, phantom units granted under the APL LTIPs generally had vesting periods of four years. 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 March 31, 2013, 292,809 units will vest within the following twelve months.
All phantom units outstanding under the APL LTIPs at March 31, 2013 include DERs. The amounts paid with respect to APL LTIP DERs were $0.6 million and $0.2 million for the three months ended March 31, 2013 and 2012, respectively. 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:
Three Months Ended March 31, | ||||||||||||||||
2013 | 2012 | |||||||||||||||
Number of Units | Weighted Average Grant Date Fair Value | Number of Units | Weighted Average Grant Date Fair Value | |||||||||||||
Outstanding, beginning of year | 1,053,242 | $ | 33.21 | 394,489 | $ | 21.63 | ||||||||||
Granted | 6,804 | 33.06 | 4,132 | 36.29 | ||||||||||||
Vested and issued(1) | (2,963 | ) | 28.94 | (8,054 | ) | 39.78 | ||||||||||
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Outstanding, end of period(2)(3) | 1,057,083 | $ | 33.22 | 390,567 | $ | 21.41 | ||||||||||
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Vested and not issued(4) | — | $ | — | 4,125 | $ | 44.51 | ||||||||||
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|
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| |||||||||
Non-cash compensation expense recognized (in thousands) | $ | 4,384 | $ | 978 | ||||||||||||
|
|
|
|
(1) | The intrinsic values for phantom unit awards vested and issued during the three months ended March 31, 2013 and 2012 were $0.1 million and $0.3 million, respectively. |
(2) | There were 21,767 and 16,692 outstanding phantom unit awards at March 31, 2013 and 2012, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards. |
46
(3) | The aggregate intrinsic values for phantom unit awards outstanding at March 31, 2013 and 2012 were $36.6 million and $13.8 million, respectively. |
(4) | The aggregate intrinsic value for phantom unit awards vested but not issued at March 31, 2012 was $0.2 million. |
At March 31, 2013, APL had approximately $19.1 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.
NOTE 17 – OPERATING SEGMENT INFORMATION
The Partnership’s operations include three reportable operating segments (see Note 1). 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):
Three Months Ended March 31, | ||||||||
2013 | 2012 | |||||||
Atlas Resource: | ||||||||
Revenues | $ | 112,048 | $ | 71,101 | ||||
Operating costs and expenses | (88,555 | ) | (60,967 | ) | ||||
Depreciation, depletion and amortization expense | (21,208 | ) | (9,108 | ) | ||||
Loss on asset sales and disposal | (702 | ) | (7,005 | ) | ||||
Interest expense | (6,889 | ) | (150 | ) | ||||
�� |
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|
| |||||
Segment loss | $ | (5,306 | ) | $ | (6,129 | ) | ||
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| |||||
Atlas Pipeline: | ||||||||
Revenues | $ | 409,881 | $ | 293,136 | ||||
Operating costs and expenses | (361,718 | ) | (257,195 | ) | ||||
Depreciation, depletion and amortization expense | (30,458 | ) | (20,842 | ) | ||||
Interest expense | (18,686 | ) | (8,708 | ) | ||||
Loss on early extinguishment of debt | (26,582 | ) | — | |||||
|
|
|
| |||||
Segment income (loss) | $ | (27,563 | ) | $ | 6,391 | |||
|
|
|
| |||||
Corporate and other: | ||||||||
Revenues | $ | 173 | $ | 390 | ||||
Operating costs and expenses | (8,763 | ) | (15,561 | ) | ||||
Interest expense | (235 | ) | (233 | ) | ||||
|
|
|
| |||||
Segment loss | $ | (8,825 | ) | $ | (15,404 | ) | ||
|
|
|
| |||||
Reconciliation of segment income (loss) to net loss: | ||||||||
Segment income (loss): | ||||||||
Atlas Resource | $ | (5,306 | ) | $ | (6,129 | ) | ||
Atlas Pipeline | (27,563 | ) | 6,391 | |||||
Corporate and other | (8,825 | ) | (15,404 | ) | ||||
|
|
|
| |||||
Net loss | $ | (41,694 | ) | $ | (15,142 | ) | ||
|
|
|
| |||||
Capital expenditures: | ||||||||
Atlas Resource | $ | 58,487 | $ | 18,958 | ||||
Atlas Pipeline | 108,516 | 81,167 | ||||||
Corporate and other | — | — | ||||||
|
|
|
| |||||
Total capital expenditures | $ | 167,003 | $ | 100,125 | ||||
|
|
|
|
March 31, 2013 | December 31, 2012 | |||||||
Balance sheet: | ||||||||
Goodwill: | ||||||||
Atlas Resource | $ | 31,784 | $ | 31,784 | ||||
Atlas Pipeline | 319,285 | 319,285 | ||||||
Corporate and other | — | — | ||||||
|
|
|
| |||||
$ | 351,069 | $ | 351,069 | |||||
|
|
|
|
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Total assets: | ||||||||
Atlas Resource | $ | 1,469,063 | $ | 1,498,952 | ||||
Atlas Pipeline | 3,154,430 | 3,065,638 | ||||||
Corporate and other | 25,983 | 32,604 | ||||||
|
|
|
| |||||
$ | 4,649,476 | $ | 4,597,194 | |||||
|
|
|
|
NOTE 18 – SUBSEQUENT EVENTS
Cash Distribution. On April 25, 2013, the Partnership declared a cash distribution of $0.31 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $15.9 million distribution will be paid on May 20, 2013 to unitholders of record at the close of business on May 6, 2013.
Atlas Pipeline
Senior Note Offering. On May 7, 2013, APL priced a private placement offering of $400.0 million aggregate principal amount of 4.75% Senior Notes due 2021 (“4.75% APL Senior Notes”). The 4.75% APL Senior Notes were priced at par and APL intends to use the net proceeds from this offering of approximately $392.0 million to reduce obligations under its revolving credit facility, and for general partnership purposes. The 4.75% APL Senior Notes are expected to be issued on May 10, 2013, subject to customary closing conditions. The 4.75% APL Senior Notes will not be registered under the Securities Act or the securities laws of any state. The 4.75% APL Senior Notes may be resold by the initial purchasers pursuant to Rule 144A and Regulation S under the Securities Act.
TEAK Acquisition. On May 7, 2013 APL completed an acquisition of TEAK Midstream Holdings, LLC and its wholly owned subsidiary, TEAK Midstream, L.L.C. (“TEAK”), whereby APL purchased 100% of the outstanding ownership interests in TEAK for approximately $1.0 billion in cash, subject to customary purchase price adjustments and other adjustments contemplated by the purchase and sale agreement (the “TEAK Acquisition”). TEAK’s assets primarily include gas gathering, processing and treating facilities in South Texas. The effective date of the TEAK Acquisition is April 1, 2013.
In connection with the TEAK acquisition, APL entered into a Class D preferred unit purchase agreement for the private placement of $400.0 million of its Class D convertible preferred units (“Class D Preferred Units”) to third party investors, at a negotiated price per unit of $29.75. The Class D Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class D Preferred Units are convertible, in whole but not in part, at APL’s option into common units, beginning one year from the date of issuance subject to customary anti-dilution adjustments. Unless previously converted, all Class D Preferred Units will convert into common units at the end of eight full quarterly periods from the date of issuance. The Class D Preferred Units will receive distributions of additional Class D Preferred Units, based on the distributions paid to APL’s common unitholders, for the first four full quarterly periods following their issuance and thereafter, the distributions will be paid in additional Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at APL’s discretion. Upon the issuance of the Class D Preferred Units, APL entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class D Preferred Units. APL will use its commercially reasonable efforts to have the registration statement declared effective within 180 days of the date of conversion. In addition, the Partnership as general partner contributed cash of $8.3 million to maintain its 2% general partnership interest, upon the issuance of the Class D Preferred Units. The proceeds were used to fund a portion of the purchase price of the TEAK Acquisition.
On April 17, 2013, in order to partially finance the TEAK Acquisition, APL issued 11,845,000 of its common units (including 1,545,000 common units to cover the underwriters’ over-allotment option) in a public offering at a price $34.00 per unit. APL received approximately $396.7 in net proceeds after underwriting commissions and estimated expenses, including $8.3 million paid by the Partnership in order to maintain its 2% general partnership interest.
On April 19, 2013, APL entered into an amendment to its amended and restated credit agreement, which among other changes, (1) allowed the TEAK Acquisition to be a Permitted Investment, as defined in the credit agreement; (2) will not require the joint venture interests, that are included in the TEAK Acquisition, to be guarantors; (3) modified the definitions of Consolidated Funded Debt Ratio, Interest Coverage Ration and Consolidated EBITDA to allow for a period following the TEAK Acquisition whereby the terms for calculating each of these ratios have been adjusted; (4) permitted the Consolidated Funded Debt Ratio, as defined in the credit agreement, to be greater than (i) 5.50 to 1.00 for the last day of any fiscal quarter during an Acquisition Period (as defined in the credit agreement), (ii) 5.75 to 1.00 for the last day of the fiscal quarter in
48
which the TEAK Acquisition was consummated, (iii) 5.50 to 1.00 for the last day of the two fiscal quarters immediately following the fiscal quarter in which the TEAK Acquisition was consummated, or (iv) 5.00 to 1.00 for the last day of any other fiscal quarter; and (5) permitted the payment of cash distributions, if any, on the Class D Preferred Units assuming APL has a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50.0 million.
Cash Distribution. On April 24, 2013, APL declared a cash distribution of $0.59 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $49.3 million distribution, including $4.0 million to the Partnership as general partner, will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013.
Atlas Resource
Cash Distribution. On April 25, 2013, ARP declared a cash distribution of $0.51 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $25.3 million distribution, including $0.9 million to the Partnership as general partner and $2.0 million to its preferred limited partners, will be paid on May 15, 2013 to unitholders of record at the close of business on May 6, 2013.
NOTE 19 – RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS
The Partnership has restated the consolidated statements of comprehensive income (loss) for the three months ended March 31, 2013 and 2012 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 revise certain headings in such financial statements. The previously reported amounts of comprehensive income (loss) attributable to common limited partners did not change for either period.
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ITEM 4: CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation in connection with the Original Filing, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2013, our disclosure controls and procedures were effective at the reasonable assurance level. 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 in our internal control over financial reporting that existed as of March 31, 2013 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 disclosure controls and procedures were not effective at a reasonable assurance level as of March 31, 2013. This conclusion reflects disclosure controls and procedures in place, and events that had occurred, as of March 31, 2013.
The material weakness resulted in the reordering and renaming of certain line items within the consolidated 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 statements of comprehensive income (loss). As of June 30, 2013, the material weakness described above has been remediated.
There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II
ITEM 6: | EXHIBITS |
Exhibit No. | Description | |
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) | |
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) | |
10.3(j) | Amendment No. 10 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(39) |
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Exhibit No. | Description | |
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 | Form of Phantom Grant under 2006 Long-Term Incentive Plan(44) | |
10.8 | 2010 Long-Term Incentive Plan(16) | |
10.9 | Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan(32) | |
10.10 | Form of Stock Option Grant under 2010 Long-Term Incentive Plan(32) | |
10.11(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) | |
10.11(b) | Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011(25) | |
10.11(c) | Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011(26) | |
10.11(d) | Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of May 31, 2012(18) | |
10.11(e) | Amendment No. 3 to the Amended and Restated Credit Agreement(34) | |
10.11(f) | Amendment No. 4 to the Amended and Restated Credit Agreement(11) | |
10.12 | 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) | |
10.13(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) | |
10.13(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) |
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Exhibit No. | Description | |
10.13(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) | |
10.14 | 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) | |
10.15 | 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) | |
10.16 | 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) | |
10.17 | Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011(12) | |
10.18 | Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011(12) | |
10.19 | Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011(21) | |
10.20 | Employment Agreement between Atlas Energy, L.P. and Matthew A. Jones dated as of November 4, 2011(32) | |
10.21 | Employment Agreement between Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Patrick J. McDonie dated as of July 3, 2012(35) | |
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) |
53
Exhibit No. | Description | |
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) | 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(d) | Third Amendment to Amended and Restated Credit Agreement dated as of December 20, 2012(36) | |
10.25(e) | 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 | Atlas Pipeline Partners, L.P. Long-Term Incentive Plan(27) | |
10.29 | Atlas Pipeline Partners, L.P. Amended and Restated 2010 Long-Term Incentive Plan(20) | |
10.30(a) | 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) | |
10.30(b) | First Amendment to Credit Agreement and First Amendment to Guaranty Agreement dated as of March 1, 2013(3) | |
10.31 | Registration Rights Agreement, dated as of April 30, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein(31) | |
10.32 | Registration Rights Agreement, dated as of July 25, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein(17) | |
10.33 | 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) | |
10.34 | 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) | |
10.35 | 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) | |
10.36 | 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) | |
10.37 | 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) | |
10.38 | 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) |
54
Exhibit No. | Description | |
10.39 | Equity Distribution Agreement dated November 5, 2012, by and between Atlas Pipeline Partners, L.P. and Citigroup Global Markets Inc.(43) | |
10.40 | Purchase and Sale Agreement, dated as of April 16, 2013, among TEAK Midstream Holdings, LLC, TEAK Midstream, L.L.C. and Atlas Pipeline Mid-Continent Holdings, LLC. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Registration S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request(29) | |
10.41 | Registration Rights Agreement, dated February 11, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein(38) | |
10.42 | Class D Preferred Unit Purchase Agreement, dated as of April 16, 2013, among Atlas Pipeline Partners, L.P. and the various purchasers party thereto(29) | |
10.43 | Registration Rights Agreement, dated May 7, 2013, by and among Atlas Pipeline Partners, L.P. and the purchasers named therein(39) | |
10.44 | Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional, and Other Special Rights and Qualifications, Limitations and Restrictions Thereof, dated as of May 7, 2013(39) | |
31.1 | Rule 13(a)-14(a)/15(d)-14(a) Certification | |
31.2 | Rule 13(a)-14(a)/14(d)-14(a) Certification | |
32.1 | Section 1350 Certification | |
32.2 | Section 1350 Certification | |
101.INS | XBRL Instance Document(45) | |
101.SCH | XBRL Schema Document(45) | |
101.CAL | XBRL Calculation Linkbase Document(45) | |
101.LAB | XBRL Label Linkbase Document(45) | |
101.PRE | XBRL Presentation Linkbase Document(45) | |
101.DEF | XBRL Definition Linkbase Document(45) |
(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 current report on Form 8-K filed on March 4, 2013. |
(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. |
55
(11) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 23, 2013. |
(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 Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q filed on March 31, 2011. |
(21) | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2011. |
(22) | Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011. |
(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. |
(27) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s annual report on Form 10-K for the year ended December 31, 2009. |
(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 Pipeline Partners, L.P.’s current report on Form 8-K filed on April 17, 2013. |
(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 Pipeline Partners, L.P.’s current report on Form 8-K filed on February 12, 2013. |
(39) | Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 8, 2013. |
(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 the Original Filing. |
(45) | 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 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 of the General Partner |
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