10-Q 1 d393566d10q.htm ATLAS ENERGY, L.P. - FORM 10-Q Atlas Energy, L.P. - Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     

Commission file number: 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 August 1, 2012 was 51,325,287.

 

 

 


Table of Contents

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

 

     PAGE  

PART I. FINANCIAL INFORMATION

  

Item 1. Financial Statements (Unaudited)

     3   

Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011

     3   

Consolidated Combined Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011

     4   

Consolidated Combined Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2012 and 2011

     5   

Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2012

     6   

Consolidated Combined Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011

     7   

Notes to Consolidated Combined Financial Statements

     8   

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     52   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     77   

Item 4. Controls and Procedures

     81   

PART II. OTHER INFORMATION

  

Item 6. Exhibits

     82   

SIGNATURES

     87   

 

 

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PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

     June 30,      December 31,  
     2012      2011  
ASSETS      

Current assets:

     

Cash and cash equivalents

   $ 32,697       $ 77,376   

Accounts receivable

     117,427         136,853   

Current portion of derivative asset

     53,470         15,447   

Subscriptions receivable

     —           34,455   

Prepaid expenses and other

     19,004         24,779   
  

 

 

    

 

 

 

Total current assets

     222,598         288,910   

Property, plant and equipment, net

     2,457,539         2,093,283   

Intangible assets, net

     113,111         104,777   

Investment in joint venture

     86,092         86,879   

Goodwill, net

     31,784         31,784   

Long-term derivative asset

     49,233         30,941   

Other assets, net

     53,638         48,197   
  

 

 

    

 

 

 
   $ 3,013,995       $ 2,684,771   
  

 

 

    

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL      

Current liabilities:

     

Current portion of long-term debt

   $ 3,908       $ 2,085   

Accounts payable

     64,437         93,554   

Liabilities associated with drilling contracts

     18,757         71,719   

Accrued producer liabilities

     56,494         88,096   

Current portion of derivative payable to Drilling Partnerships

     15,880         20,900   

Accrued interest

     2,186         1,629   

Accrued well drilling and completion costs

     34,936         17,585   

Accrued liabilities

     56,107         61,653   
  

 

 

    

 

 

 

Total current liabilities

     252,705         357,221   

Long-term debt, less current portion

     853,065         522,055   

Long-term derivative payable to Drilling Partnerships

     8,508         15,272   

Asset retirement obligations and other

     58,638         46,142   

Commitments and contingencies

     

Partners’ Capital:

     

Common limited partners’ interests

     438,011         554,999   

Accumulated other comprehensive income

     22,247         29,376   
  

 

 

    

 

 

 
     460,258         584,375   

Non-controlling interests

     1,380,821         1,159,706   
  

 

 

    

 

 

 

Total partners’ capital

     1,841,079         1,744,081   
  

 

 

    

 

 

 
   $ 3,013,995       $ 2,684,771   
  

 

 

    

 

 

 

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2012     2011     2012     2011  

Revenues:

        

Gas and oil production

   $ 19,460      $ 17,723      $ 36,624      $ 35,349   

Well construction and completion

     12,241        10,954        55,960        28,679   

Gathering and processing

     256,542        345,734        561,762        625,952   

Administration and oversight

     1,315        1,375        4,146        2,736   

Well services

     5,252        4,855        10,258        10,141   

Gain (loss) on mark-to-market derivatives

     67,847        6,837        55,812        (14,808

Other, net

     504        21,414        3,305        25,767   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     363,161        408,892        727,867        713,816   
  

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

        

Gas and oil production

     4,447        4,042        8,952        7,963   

Well construction and completion

     10,606        9,284        48,301        24,305   

Gathering and processing

     213,673        293,471        465,597        530,455   

Well services

     2,414        1,674        4,844        4,034   

General and administrative

     37,607        22,239        74,855        38,429   

Depreciation, depletion and amortization

     32,534        27,370        62,484        53,977   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     301,281        358,080        665,033        659,163   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     61,880        50,812        62,834        54,653   

Gain (loss) on asset sales and disposal

     (16     (233     (7,021     255,714   

Interest expense

     (10,294     (6,567     (19,385     (24,645

Loss on early extinguishment of debt

     —          (19,574     —          (19,574
  

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations

     51,570        24,438        36,428        266,148   

Discontinued operations:

        

Loss from discontinued operations

     —          —          —          (81
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     51,570        24,438        36,428        266,067   

Income attributable to non-controlling interests

     (59,191     (7,925     (62,556     (219,303
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) after non-controlling interests

     (7,621     16,513        (26,128     46,764   

Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))

     —          —          —          (4,711
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ (7,621   $ 16,513      $ (26,128   $ 42,053   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners per unit – basic:

        

Income (loss) from continuing operations attributable to common limited partners

   $ (0.15   $ 0.31      $ (0.51   $ 0.91   

Loss from discontinued operations attributable to common limited partners

     —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ (0.15   $ 0.31      $ (0.51   $ 0.91   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners per unit – diluted:

        

Income (loss) from continuing operations attributable to common limited partners

   $ (0.15   $ 0.30      $ (0.51   $ 0.89   

Loss from discontinued operations attributable to common limited partners

     —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ (0.15   $ 0.30      $ (0.51   $ 0.89   
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average common limited partner units outstanding:

        

Basic

     51,318        51,235        51,306        45,156   
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

     51,318        52,965        51,306        46,143   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) attributable to common limited partners:

        

Income (loss) from continuing operations

   $ (7,621   $ 16,513      $ (26,128   $ 42,063   

Loss from discontinued operations

     —          —          —          (10
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ (7,621   $ 16,513      $ (26,128   $ 42,053   
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2012     2011     2012     2011  

Net income

   $ 51,570      $ 24,438      $ 36,428      $ 266,067   

Income attributable to non-controlling interests

     (59,191     (7,925     (62,556     (219,303

Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of the acquisition (see Note 2))

     —          —          —          (4,711
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common unitholders

     (7,621     16,513        (26,128     42,053   

Other comprehensive income (loss):

        

Changes in fair value of derivative instruments accounted for as cash flow hedges

     (514     6,407        13,655        6,849   

Less: reclassification adjustment for realized gains in net income (loss)

     (5,631     126        (7,085     (5,904

Changes in non-controlling interest related to items in other comprehensive income (loss)

     (4,569     (1,490     (13,699     (2,954
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other comprehensive income (loss)

     (10,714     5,043        (7,129     (2,009
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss) attributable to common unitholders

   $ (18,335   $ 21,556      $ (33,257   $ 40,044   
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(Unaudited)

 

           Accumulated              
     Common Limited
Partners’ Capital
   

Other

Comprehensive

   

Non-

Controlling

   

Total

Partners’

 
     Units      Amount     Income     Interest     Capital  

Balance at January 1, 2012

     51,278,362       $ 554,999      $ 29,376      $ 1,159,706      $ 1,744,081   

Distribution of Atlas Resource Partners, L.P. units

     —           (84,892     —          84,892        —     

Distributions to non-controlling interests

     —           —          —          (53,584     (53,584

Unissued common units under incentive plan

     —           8,817        —          6,839        15,656   

Issuance of units under incentive plans

     45,232         97        —          77        174   

Non-controlling interests’ capital contribution

     —           —          —          119,389        119,389   

Atlas Pipeline Partners L.P. purchase and retirement of treasury stock

     —           —          —          (695     (695

Distributions paid to common limited partners

     —           (25,140     —          —          (25,140

Distribution equivalent rights paid on unissued units under incentive plans

     —           (977     —          (823     (1,800

Gain on sale of subsidiary units

     —           11,235        —          (11,235     —     

Other comprehensive income (loss)

     —           —          (7,129     13,699        6,570   

Net income (loss)

     —           (26,128     —          62,556        36,428   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance at June 30, 2012

     51,323,594       $ 438,011      $ 22,247      $ 1,380,821      $ 1,841,079   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

     Six Months Ended June 30,  
     2012     2011  

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net income

   $ 36,428      $ 266,067   

Loss from discontinued operations

     —          (81
  

 

 

   

 

 

 

Income from continuing operations

     36,428        266,148   

Adjustments to reconcile net income from continuing operations to net cash provided by (used in) operating activities:

    

Depreciation, depletion and amortization

     62,484        53,977   

Amortization of deferred finance costs

     2,954        7,233   

Non-cash (gain) loss on derivative value, net

     (61,401     47,725   

Non-cash compensation expense

     15,835        6,130   

(Gain) loss on asset sales and disposal

     7,021        (255,714

Loss on early extinguishment of debt

     —          19,574   

Distributions paid to non-controlling interests

     (54,407     (38,642

Equity income in unconsolidated companies

     (3,330     (20,956

Distributions received from unconsolidated companies

     3,992        16,083   

Changes in operating assets and liabilities:

    

Accounts receivable and prepaid expenses and other

     59,656        (33,337

Accounts payable and accrued liabilities

     (93,917     (9,877
  

 

 

   

 

 

 

Net cash provided by (used in) continuing operating activities

     (24,685     58,344   

Net cash used in discontinued operating activities

     —          (81
  

 

 

   

 

 

 

Net cash provided by (used in) operating activities

     (24,685     58,263   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Capital expenditures

     (192,040     (106,351

Net cash paid for acquisitions

     (241,925     —     

Investments in unconsolidated companies

     —          (97,250

Net proceeds from asset disposals

     —          411,520   

Other

     1,049        (1,903
  

 

 

   

 

 

 

Net cash provided by (used in) investing activities

     (432,916     206,016   
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Borrowings under credit facilities

     648,500        457,000   

Repayments under credit facilities

     (316,000     (384,500

Repayments of long-term debt

     —          (314,962

Payment of premium on early retirement of debt

     —          (14,352

Net proceeds from subsidiary equity offerings

     119,389        —     

Redemption of Atlas Pipeline Partners, L.P.’s preferred units

     —          (8,000

Distributions paid to unitholders

     (25,140     (7,583

Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)

     —          120,913   

Deferred financing costs and other

     (13,827     (4,350
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     412,922        (155,834
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     (44,679     108,445   

Cash and cash equivalents, beginning of year

     77,376        247   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 32,697      $ 108,692   
  

 

 

   

 

 

 

See accompanying notes to consolidated combined financial statements

 

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED COMBINED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: ATLS).

At June 30, 2012, the Partnership’s operations primarily consisted of its ownership interests in the following entities:

 

   

Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas and oil, with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At June 30, 2012, the Partnership owned 100% of the general partner Class A units and incentive distribution rights through which it manages and effectively controls ARP, and common units representing an approximate 63.7% limited partner interest in ARP (see Note 18);

 

   

Atlas Pipeline Partners, L.P. (“APL”), a publicly-traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions of the United States. At June 30, 2012, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 10.5% 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 June 30, 2012, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 7).

In February 2012, the board of directors of the Partnership’s General Partner (“the Board”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of the Partnership’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to the Partnership’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.

The accompanying consolidated combined financial statements, which are unaudited except that the balance sheet at December 31, 2011 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated combined financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. Certain amounts in the prior year’s consolidated combined financial statements have also been reclassified to conform to the current year presentation. The results of operations for the three and six months ended June 30, 2012 may not necessarily be indicative of the results of operations for the full year ending December 31, 2012.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Combination

The consolidated combined financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at June 30, 2012 except for ARP and APL, which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP and APL, the Partnership consolidates the

 

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financial statements of ARP and APL into its consolidated combined financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP and APL are reflected as income (loss) attributable to non-controlling interests in its consolidated combined statements of operations and as a component of partners’ capital on its consolidated combined balance sheets. All material intercompany transactions have been eliminated.

On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, a partnership management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of the Partnership’s general partner (see Note 3). Management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on the Partnership’s consolidated combined balance sheets. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in the Partnership’s consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, the Partnership reflected the impact of the acquisition of the Transferred Business on its consolidated combined financial statements in the following manner:

 

   

Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital;

 

   

Retrospectively adjusted its consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect its results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

 

   

Adjusted the presentation of the Partnership’s consolidated combined statements of operations for the six months ended June 30, 2011 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated combined financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which ARP has an interest (“the Drilling Partnerships”). Such interests typically range from 20% to 41%. The Partnership’s financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

The Partnership’s consolidated combined financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the West OK natural gas gathering system and processing plants and a 72.8% undivided interest in the West TX natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its consolidated combined statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests within partners’ capital on its consolidated combined balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which was reflected within non-controlling interests on the Partnership’s consolidated combined balance sheets.

The 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.

 

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Use of Estimates

The preparation of the Partnership’s consolidated combined financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated combined financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated combined financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition (see “Principles of Consolidation and Combination”). Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and six months ended June 30, 2012 and 2011 represent actual results in all material respects (see “Revenue Recognition”).

Receivables

Accounts receivable on the consolidated combined 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 June 30, 2012 and December 31, 2011, ARP and APL had recorded no allowance for uncollectible accounts receivable on the Partnership’s consolidated combined balance sheets.

Inventory

ARP and APL had $11.0 million and $16.0 million of inventory at June 30, 2012 and December 31, 2011, respectively, which were included within prepaid expenses and other current assets on the Partnership’s consolidated combined 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 consists of APL’s natural gas liquids line fill, which represents amounts receivable for natural gas liquids (“NGL’s”) delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then 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 and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation.

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.

 

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ARP’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated investment partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of an ARP complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated combined statements of operations. Upon the sale of an individual ARP well, ARP credits the proceeds to accumulated depreciation and depletion within the Partnership’s consolidated combined balance sheets. Upon ARP’s sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated combined statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

The Partnership and its subsidiaries review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of ARP’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on ARP’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. ARP estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions, an additional carried interest (generally 5% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. ARP cannot predict what reserve revisions may be required in future periods.

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a well or Drilling Partnership becomes uneconomic under the terms of the Drilling Partnership’s agreement in

 

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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 and six months ended June 30, 2012 and 2011.

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, 2011, the Partnership recognized $7.0 million of asset impairment related to ARP’s gas and oil properties within property, plant and equipment on its consolidated combined balance sheet for its shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of the gas and oil properties being in excess of ARP’s estimate of their fair value at December 31, 2011. The estimate of fair value of the 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 and six months ended June 30, 2012 and 2011.

Capitalized Interest

ARP and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP and APL in the aggregate were 5.8% and 7.3% for the three months ended June 30, 2012 and 2011, respectively, and 6.2% and 7.1% for the six months ended June 30, 2012 and 2011, respectively. The aggregate amounts of interest capitalized by ARP and APL were $2.3 million and $1.1 million for the three months ended June 30, 2012 and 2011, respectively, and $4.6 million and $1.5 million for the six months ended June 30, 2012 and 2011, respectively.

Intangible Assets

Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions, which APL amortizes over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length. APL completed the acquisition of a gas gathering system in February 2012 and recognized $10.6 million related to customer contracts with an estimated useful life of 14 years. APL completed the acquisition of two gas gathering systems in June 2012 and recognized $9.6 million related to customer contracts with an estimated useful life of 10 years. The initial recording of these transactions was based upon preliminary valuation assessments and is subject to change.

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.

 

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The following table reflects the components of intangible assets being amortized at June 30, 2012 and December 31, 2011 (in thousands):

 

     June 30,
2012
    December 31,
2011
    Estimated
Useful Lives
In Years

Gross Carrying Amount:

      

Customer contracts and relationships

   $ 225,543      $ 205,313      2 – 14

Partnership management and operating contracts

     14,344        14,344      13
  

 

 

   

 

 

   
   $ 239,887      $ 219,657     
  

 

 

   

 

 

   

Accumulated Amortization:

      

Customer contracts and relationships

   $ (113,841   $ (102,037  

Partnership management and operating contracts

     (12,935     (12,843  
  

 

 

   

 

 

   
   $ (126,776   $ (114,880  
  

 

 

   

 

 

   

Net Carrying Amount:

      

Customer contracts and relationships

   $ 111,702      $ 103,276     

Partnership management and operating contracts

     1,409        1,501     
  

 

 

   

 

 

   
   $ 113,111      $ 104,777     
  

 

 

   

 

 

   

Amortization expense on intangible assets was $6.0 million for both the three months ended June 30, 2012 and 2011 and $11.9 million for both the six months ended June 30, 2012 and 2011. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2012—$24.4 million; 2013—$25.0 million; 2014—$21.4 million; 2015—$16.4 million; and 2016—$16.4 million.

Goodwill

At June 30, 2012 and December 31, 2011, the Partnership had $31.8 million of goodwill recorded in connection with prior ARP consummated acquisitions. There were no changes in the carrying amount of goodwill for the three and six months ended June 30, 2012 and 2011.

ARP tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to 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, 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 also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. During the three and six months ended June 30, 2012 and 2011, no impairment indicators arose, and no goodwill impairments were recognized 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 combined balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated combined balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 9).

Derivative Instruments

ARP and APL enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 10). The derivative instruments recorded in the consolidated combined balance sheets were measured as either an asset or liability at fair value. Changes in ARP’s and APL’s derivative instrument’s fair value are recognized currently in the Partnership’s consolidated combined statements of operations unless specific hedge accounting criteria are met.

 

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Asset Retirement Obligations

ARP recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 8). ARP also recognizes 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.

Stock-Based Compensation

The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated combined financial statements based on their fair values (see Note 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) from continuing operations and net income (loss) from discontinued operations allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data):

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2012     2011     2012     2011  
Continuing operations:         

Net income

   $ 51,570      $  24,438      $ 36,428      $ 266,148   

Income attributable to non-controlling interests

     (59,191     (7,925     (62,556     (219,374

Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition (see Note 2))

     —          —          —          (4,711
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

     (7,621     16,513        (26,128     42,063   

Less: Net income attributable to participating securities – phantom units(1)

     —          (512     —          (820
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit

   $ (7,621   $ 16,001      $ (26,128   $ 41,243   
  

 

 

   

 

 

   

 

 

   

 

 

 

Discontinued operations:

        

Net loss

   $ —        $ —        $ —        $ (81

Loss attributable to non-controlling interests

     —          —          —          71   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit

   $ —        $ —        $ —        $ (10
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three and six months ended June 30, 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,101,083 and 2,015,017 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.

 

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Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 16).

The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
 
     2012      2011      2012      2011  

Weighted average number of common limited partners per unit—basic

     51,318         51,235         51,306         45,156   

Add effect of dilutive incentive awards(1)

     —           1,730         —           987   
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average number of common limited partners per unit—diluted

     51,318         52,965         51,306         46,143   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

For the three and six months ended June 30, 2012, approximately 3,084,000 units and 2,673,000 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 must pay ARP the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, ARP classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated combined balance sheets. ARP recognizes well services revenues at the time the services are performed. ARP is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within the Partnership’s consolidated combined statements of operations.

ARP generally sells natural gas, crude oil and NGLs at prevailing market prices. Generally, ARP’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed 2 business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil and NGLs, in which ARP has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing 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 NGLs which are extracted and sells them for its own account. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the BTU quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/or (ii) aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in BTU content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic.

ARP and APL accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from ARP’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). ARP and APL had unbilled revenues at June 30, 2012 and December 31, 2011 of $69.1 million and $81.2 million, respectively, which were included in accounts receivable within the Partnership’s consolidated combined 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 accounting principles generally accepted in the United States, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Recently Adopted Accounting Standards

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“Update 2011-12”). The amendments in this update effectively defer the implementation of the changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. Under each methodology, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12.

 

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These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included consolidated combined statements of comprehensive income (loss) within this Form 10-Q upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities (“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership has elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012 (see Note 10). The adoption had no material impact on the Partnership’s financial position or results of operations.

In September 2011, the FASB issued ASU 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“Update 2011-08”). The amendments in Update 2011-08 allow an entity to first assess qualitative factors in determining the necessity of performing the two-step quantitative goodwill impairment test. If, after assessing qualitative factors, an entity determines it is not likely that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. Under the amendments in Update 2011-08, an entity has the option to bypass the qualitative assessment and proceed directly to performing the first step of the two-step impairment test. The amendments are effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Partnership adopted the amendments of Update 2011-08 upon its effective date of January 1, 2012. The adoption had no material impact on the Partnership’s financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (see Note 11). The adoption had no material impact on the Partnership’s financial position or results of operations.

Recently Issued Accounting Standards

In July 2012, the FASB issued ASU 2012-02, Intangibles – Goodwill and Other (Topic 350): Testing Indefinite- Lived Intangible Assets for Impairment (“Update 2012-02”). The amendments in Update 2012-02 allow an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. The “more likely than not” threshold is defined as having a likelihood of more than 50 percent. If, after assessing qualitative factors, an entity determines it is not likely that the indefinite-lived intangible asset is impaired, then no further action is required. If impairment is deemed more likely than not, the entity is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount of the asset. Additionally, under the amendments in Update 2012-02, an entity has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption being permitted. The Partnership will apply the requirements of Update 2012-02 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

 

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NOTE 3 – ACQUISITION FROM ATLAS ENERGY, INC.

On February 17, 2011, the Partnership acquired the Transferred Business from AEI, including the following exploration and production assets that were transferred to ARP on March 5, 2012:

 

   

AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which ARP funds a portion of its natural gas and oil well drilling;

 

   

proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee; and

 

   

certain producing natural gas and oil properties, upon which ARP is the developer and producer.

In addition to the exploration and production assets, the Transferred Business also included all of the ownership interests in Atlas Energy GP, LLC, the Partnership’s general partner, and a direct and indirect ownership interest in Lightfoot.

For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. In connection with the transaction, the Partnership also received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain liabilities assumed by the Partnership, including certain amounts subject to a reconciliation period following the consummation of the transaction. The reconciliation period was assumed by ARP on March 5, 2012 and remains ongoing at June 30, 2012, and certain amounts included within the contractual cash transaction adjustment are in dispute between the parties. The resolution of the disputed amounts could result in ARP being required to repay a portion of the cash transaction adjustment (see Note 13). Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million.

Concurrent with the Partnership’s acquisition of the Transferred Business on February 17, 2011, including assets and liabilities transferred to ARP on March 5, 2012, AEI completed its merger with Chevron Corporation (“Chevron”), whereby AEI became a wholly owned subsidiary of Chevron. Also concurrent with the Partnership’s acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”; see Note 5). APL received $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC (“Williams”) in connection with the formation of the Laurel Mountain joint venture.

Management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. As such, the Partnership recognized the assets acquired and liabilities assumed at historical carrying value at the date of acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on its consolidated combined balance sheet. The Partnership recognized a non-cash decrease of $261.0 million in partners’ capital on its consolidated combined balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying value of the assets acquired and liabilities assumed by the Partnership, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

 

Cash

   $  153,350   

Accounts receivable

     18,090   

Accounts receivable – affiliate

     45,682   

Prepaid expenses and other

     6,955   
  

 

 

 

Total current assets

     224,077   

Property, plant and equipment, net

     516,625   

Goodwill

     31,784   

Intangible assets, net

     2,107   

Other assets, net

     20,416   
  

 

 

 

Total long-term assets

     570,932   
  

 

 

 

Total assets acquired

   $ 795,009   
  

 

 

 

 

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Accounts payable

   $ 59,202   

Net liabilities associated with drilling contracts

     47,929   

Accrued well completion costs

     39,552   

Current portion of derivative payable to Drilling Partnerships

     25,659   

Accrued liabilities

     25,283   
  

 

 

 

Total current liabilities

     197,625   

Long-term derivative payable to Drilling Partnerships

     31,719   

Asset retirement obligations

     42,791   
  

 

 

 

Total long-term liabilities

     74,510   
  

 

 

 

Total liabilities assumed

   $ 272,135   
  

 

 

 

Historical carrying value of net assets acquired

   $ 522,874   
  

 

 

 

The Partnership reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired and retrospectively adjusted its prior year financial statements to furnish comparative information (see Note 2).

NOTE 4 – ARP ACQUISITION

On April 30, 2012, ARP acquired certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash. The assets acquired include interests in approximately 200 producing natural gas wells from the Barnett Shale, located in Bend Arch–Fort Worth Basin in North Texas, proved undeveloped acres also in the Barnett Shale and gathering pipelines and associated gathering facilities that service certain of the acquired wells. 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 placement exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (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 11). All costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

 

Assets:

  

Natural gas and oil properties

   $ 190,946   

Liabilities:

  

Asset retirement obligation

     3,903   
  

 

 

 

Net assets acquired

   $ 187,043   
  

 

 

 

The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the Carrizo acquisition, including the borrowings under ARP’s credit facility and private placement of ARP’s common units, had occurred on January 1, 2011. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the acquisition had occurred on January 1, 2011 or the results that will be attained in future periods (in thousands, except per share data; unaudited):

 

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     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2012     2011      2012     2011  

Total revenues and other

   $ 364,352      $ 422,445       $ 734,745      $ 739,272   

Net income (loss)

     47,062        27,672         29,444        271,412   

Net income (loss) attributable to common limited partners

     (9,911     19,747         (29,695     47,398   

Net income (loss) attributable to common limited partners per unit:

         

Basic

   $ (0.19   $ 0.37       $ (0.58   $ 1.03   

Diluted

   $ (0.19   $ 0.36       $ (0.58   $ 1.01   

NOTE 5 – APL INVESTMENT IN JOINT VENTURES

West Texas LPG Pipeline Limited Partnership

On May 11, 2011, APL acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“West Texas LPG”) from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. West Texas LPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. West Texas LPG is operated by Chevron Pipeline Company, a subsidiary of Chevron, which owns the remaining 80% interest. The Partnership recognizes APL’s 20% interest in West Texas LPG as an investment in joint venture on its consolidated combined balance sheets. At the acquisition date, the carrying value of the 20% interest in West Texas LPG exceeded APL’s share of the underlying net assets of West Texas LPG by approximately $49.9 million, which related to the fair value of the property, plant and equipment in excess of book value. This excess will be depreciated over approximately 38 years. APL has accounted for its ownership interest in West Texas LPG under the equity method of accounting, with recognition of its ownership interest in the income of West Texas LPG in other, net on the Partnership’s consolidated combined statements of operations. During the three and six months ended June 30, 2012, APL recognized $1.9 million and $2.8 million of equity income within other, net on the Partnership’s consolidated combined statements of operations related to its West Texas LPG interest. During the three and six months ended June 30, 2011, APL recognized $0.7 million of equity income related to its West Texas LPG interest.

Laurel Mountain

On February 17, 2011, APL completed the sale of its 49% non-controlling interest in the Laurel Mountain joint venture to AEI (see Note 3). The Laurel Mountain joint venture was formed in May 2009 by APL and subsidiaries of the Williams Companies, Inc. (NYSE: WMB; “Williams”) to own and operate APL’s Appalachian Basin natural gas gathering system. APL used the proceeds from the sale to repay its indebtedness and for general corporate purposes. APL also retained its preferred distribution rights with respect to a remaining $8.5 million note receivable due from Williams, an investment grade rated entity, related to the formation of Laurel Mountain, including interest due on this note. Since APL accounted for its ownership of Laurel Mountain as an equity investment included within investment in joint venture on the Partnership’s consolidated combined balance sheet and recognition of its ownership interest in the income of Laurel Mountain as other, net on the Partnership’s consolidated combined statements of operations, APL did not reclassify the earnings or the gain on sale related to Laurel Mountain to discontinued operations upon the sale of its ownership interest. The Partnership recognized a loss of $0.3 million and a net gain of $255.7 million during the three and six months ended June 30, 2011, respectively, which is included in gain (loss) on asset sales and disposal within the Partnership’s consolidated combined statements of operations. The Partnership also reclassified the $8.5 million note receivable previously recorded to investment in joint venture to prepaid expenses and other on the Partnership’s consolidated combined balance sheets. In December 2011, Williams made a cash payment to APL to settle the remaining $8.5 million balance on the note receivable plus accrued interest of $0.2 million.

The following tables summarize the components of equity income within other, net on the Partnership’s consolidated combined statements of operations (in thousands).

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
 
     2012      2011      2012      2011  

Equity income in Laurel Mountain

   $ —         $ —         $ —         $ 462   

Equity income in WTLPG

     1,917         687         2,813         687   
  

 

 

    

 

 

    

 

 

    

 

 

 

Equity income in joint ventures

   $ 1,917       $ 687       $ 2,813       $ 1,149   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

 

           Estimated  
     June 30,     December 31,     Useful Lives  
     2012     2011     in Years  

Natural gas and oil properties:

      

Proved properties:

      

Leasehold interests

   $ 131,734      $ 61,587     

Pre-development costs

     1,328        2,540     

Wells and related equipment

     1,003,930        828,780     
  

 

 

   

 

 

   

Total proved properties

     1,136,992        892,907     

Unproved properties

     40,805        43,253     

Support equipment

     10,714        9,413     
  

 

 

   

 

 

   

Total natural gas and oil properties

     1,188,511        945,573     

Pipelines, processing and compression facilities

     1,799,857        1,646,320        2 – 40   

Rights of way

     173,908        161,275        20 – 40   

Land, buildings and improvements

     23,820        23,416        3 – 40   

Other

     25,036        22,734        3 – 10   
  

 

 

   

 

 

   
     3,211,132        2,799,318     

Less – accumulated depreciation, depletion and amortization

     (753,593     (706,035  
  

 

 

   

 

 

   
   $ 2,457,539      $ 2,093,283     
  

 

 

   

 

 

   

In March 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 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 six months ended June 30, 2012.

During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated combined balance sheet for ARP’s shallow natural gas wells in the Niobrara Shale. This impairment related to the carrying amount of gas and oil properties being in excess of ARP’s estimate of their fair value at December 31, 2011. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

NOTE 7 – OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

 

     June 30,      December 31,  
     2012      2011  

Deferred financing costs, net of accumulated amortization of $22,285 and $19,331 at June 30, 2012 and December 31, 2011, respectively

   $ 29,154       $ 23,426   

Investment in Lightfoot

     19,398         19,514   

Security deposits

     2,532         4,584   

Other

     2,554         673   
  

 

 

    

 

 

 
   $ 53,638       $ 48,197   
  

 

 

    

 

 

 

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 9). Amortization expense of deferred finance costs was $1.6 million and $1.3 million for the three months ended June 30, 2012 and 2011, respectively, and $3.0 million and $2.6 million for the six months ended June 30, 2012 and 2011, respectively, which is recorded within interest expense on the Partnership’s consolidated combined statements of operations. During the three and six months ended June 30, 2011, APL recognized $5.2 million of accelerated amortization of deferred financing costs associated with the retirement of its 8.125% Senior Notes and partial redemption of its 8.75% Senior Notes, which is recorded within loss on early extinguishment of debt on the Partnership’s consolidated combined statements of operations. In March 2011, the Partnership recognized an additional $4.9 million of accelerated amortization of its deferred financing costs associated with the retirement of its $70.0 million credit facility, which is recorded within interest expense on the Partnership’s consolidated combined statements of operations.

 

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At June 30, 2012, the Partnership owns an approximate 12% interest in Lightfoot LP and an approximate 16% interest in Lightfoot GP, the general partner of Lightfoot LP, an entity for which Jonathan Cohen, Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot LP focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the three and six months ended June 30, 2012, the Partnership recorded equity income of $0.2 million and $0.5 million, respectively. The equity income was recorded within other, net on the Partnership’s consolidated combined statements of operations. During the three and six months ended June 30, 2012, the Partnership received net cash distributions of $0.2 million and $0.4 million, respectively. During the three months ended June 30, 2011, the Partnership recognized a gain associated with its equity ownership interest in Lightfoot of $17.6 million pertaining to its share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP (“IRP”), its metallurgical and steam coal business, in March 2011. This gain was recorded within other, net on the Partnership’s consolidated combined statements of operations. Additionally, the Partnership received a net cash distribution of $13.7 million, representing its share of the cash distribution made to investors by Lightfoot LP with proceeds from the IRP sale.

NOTE 8 – 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 recorded on the Partnership’s consolidated combined balance sheets for the periods indicated is as follows (in thousands):

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2012     2011     2012     2011  

Asset retirement obligations, beginning of period

   $ 46,538      $ 43,315      $ 45,779      $ 42,673   

Liabilities incurred

     3,911        —          4,092        93   

Liabilities settled

     (132     (33     (250     (132

Accretion expense

     729        650        1,425        1,298   
  

 

 

   

 

 

   

 

 

   

 

 

 

Asset retirement obligations, end of period

   $ 51,046      $ 43,932      $ 51,046      $ 43,932   
  

 

 

   

 

 

   

 

 

   

 

 

 

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated combined statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Partnership’s consolidated combined balance sheets. During the three and six months ended June 30, 2012, ARP incurred $3.9 million of future plugging and abandonment costs related to the acquisition of assets from Carrizo (see Note 4).

NOTE 9 – DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

     June 30,      December 31,  
     2012      2011  

ARP revolving credit facility

   $ 144,000       $ —     

APL revolving credit facility

     330,500         142,000   

APL 8.75 % Senior Notes – due 2018

     370,584         370,983   

 

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APL capital leases

     11,889        11,157   
  

 

 

   

 

 

 

Total debt

     856,973        524,140   

Less current maturities

     (3,908     (2,085
  

 

 

   

 

 

 

Total long-term debt

   $ 853,065      $ 522,055   
  

 

 

   

 

 

 

Partnership’s Credit Facility

In May 2012, the Partnership entered into a new credit facility with a syndicate of banks that matures in May 2016. The credit facility has maximum lender commitments of $50.0 million, and up to $5.0 million of the credit facility may be in the form of standby letters of credit. At June 30, 2012, no amounts were 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 reference to either LIBOR plus an applicable margin of between 3.50% and 4.50% per annum or the base rate plus an applicable margin of between 2.50% and 3.50% per annum. The applicable margin will fluctuate based on the utilization of the facility. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the borrowing base, which is included within interest expense on the Partnership’s consolidated combined statement of operations.

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.

At June 30, 2012, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.

ARP’s Credit Facility

At June 30, 2012, ARP had a senior secured credit facility with a syndicate of banks with a borrowing base of $250.0 million with $144.0 million outstanding (see Note 18). The credit facility matures in March 2016 and the borrowing base will be redetermined semi-annually in May and November. Up to $20.0 million of the credit facility may be in the form of standby letters of credit which would reduce ARP’s borrowing capacity, of which $0.6 million was outstanding at June 30, 2012, and was not reflected as borrowings on the Partnership’s consolidated combined balance sheet. ARP’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. 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 3.00% 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 2.00%. 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 combined statements of operations. At June 30, 2012, the weighted average interest rate was 3.1%.

The 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 June 30, 2012. The credit agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to four quarters (actual or annualized, as applicable) of EBITDA (as defined in the credit agreement) not greater than 3.75 to 1.0 as of the last day of any fiscal quarter, a ratio of current assets (as defined in the credit agreement) to current liabilities (as defined in the credit agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and a ratio of four quarters (actual or annualized, as applicable) of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.5 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s credit facility, its ratio of current assets to current liabilities was 1.4 to 1.0, its ratio of Total Funded Debt to EBITDA was 1.6 to 1.0 and its ratio of EBITDA to Consolidated Interest Expense was 38.1 to 1.0 at June 30, 2012.

 

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APL Credit Facility

At June 30, 2012, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $330.5 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 June 30, 2012 was 2.7%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at June 30, 2012. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated combined balance sheet at June 30, 2012. At June 30, 2012, APL had $269.4 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.

At May 31, 2012, APL entered into an amendment to its revolving credit facility agreement, which among other changes:

 

   

increased the revolving credit facility from $450.0 million to $600.0 million;

 

   

extended the maturity date from December 22, 2015 to May 31, 2017;

 

   

reduced the applicable margin used to determine interest rates by 0.50%;

 

   

revised the negative covenants to (i) permit investments in joint ventures equal to the greater of 20.0% of “Consolidated Net Tangible Assets” (as defined in APL’s credit agreement) or $340.0 million, provided APL meets certain requirements, and (ii) increased the general investment basket to 5.0% of “Consolidated Net Tangible Assets”;

 

   

revised the definition of “Consolidated EBITDA” to provide for the inclusion of the first twelve months of projected revenues for identified capital expansion projects, upon completion of the projects and contingent upon prior approval by the administrative agent. The addition from any such projects, in the aggregate, may not exceed 15.0% of unadjusted Consolidated EBITDA; and

 

   

provided for the option of additional revolving credit commitments of up to $200.0 million, upon request by APL.

Borrowings under APL’s credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by West OK and West TX joint ventures, and by the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

The events which constitute an event of default for the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner. APL was in compliance with these covenants as of June 30, 2012.

APL Senior Notes

At June 30, 2012, APL had $370.6 million principal amount outstanding of 8.75% senior unsecured notes, including a net $4.8 million unamortized premium, due on June 15, 2018 (“APL 8.75% Senior Notes”). Interest on the APL 8.75% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The APL 8.75% Senior Notes are redeemable at any time after June 15, 2013, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. The APL 8.75% Senior Notes are subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the net proceeds within 360 days. The APL 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

 

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Table of Contents

In November 2011, APL issued $150.0 million of the 8.75% Senior Notes, priced at a premium of $155.3 million, in a private placement transaction under Rule 144A and Regulation S under the Securities Act of 1933, as amended, for net proceeds of $152.4 million after underwriting commissions and other transaction costs. APL utilized the proceeds to reduce the outstanding balance on its revolving credit facility.

In April 2011, APL redeemed all of its 8.125% senior notes, due December 15, 2015, for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million. APL also redeemed $7.2 million of the APL 8.75% Senior Notes in April 2011, which were tendered upon its offer to purchase the senior notes at par. APL funded its purchase with a portion of the net proceeds from its sale of its 49% non-controlling interest in Laurel Mountain (see Note 5).

The indenture governing the APL 8.75% Senior Notes in the aggregate contains covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. APL was in compliance with these covenants as of June 30, 2012.

APL Capital Leases

At June 30, 2012 and December 31, 2011, APL had $11.9 million and $11.2 million, respectively, of long-term debt related to capital leases. For leased property and equipment meeting capital lease criteria, APL recognizes an asset within property, plant and equipment with an offsetting liability recorded within long term debt on the Partnership’s consolidated combined balance sheets based on the minimum payments required under the lease and APL’s incremental borrowing rate. During the six months ended June 30, 2012, APL recognized $1.9 million of additional assets meeting capital lease criteria within property, plant and equipment and recognized an offsetting liability within long term debt on the Partnership’s consolidated combined balance sheets. The following is a summary of the leased property under capital leases, which are included within property, plant and equipment (see Note 6) (in thousands):

 

     June 30,
2012
    December 31,
2011
 

Pipelines, processing and compression facilities

   $ 14,512      $ 12,507   

Less – accumulated depreciation

     (695     (199
  

 

 

   

 

 

 
   $ 13,817      $ 12,308   
  

 

 

   

 

 

 

Depreciation expense for leased properties was $0.2 million and $0.4 million for the three and six months ended June 30, 2012, respectively. Depreciation expense for leased properties was not material for the three and six months ended June 30, 2011. Depreciation expense for leased properties is included within depreciation and amortization expense on the Partnership’s consolidated combined statements of operations.

As of June 30, 2012, future minimum lease payments related to the capital leases are as follows (in thousands):

 

     Capital Lease
Minimum Payments
 

2012

   $ 1,665   

2013

     10,879   

2014

     64   

2015

     —     

2016

     —     

Thereafter

     —     
  

 

 

 

Total minimum lease payments

     12,608   

Less amounts representing interest

     (719
  

 

 

 

Present value of minimum lease payments

     11,889   

Less current capital lease obligations

     (3,908
  

 

 

 

Long-term capital lease obligations

   $ 7,981   
  

 

 

 

Cash payments for interest for the Partnership and its subsidiaries were $19.5 million and $18.6 million for the six months ended June 30, 2012 and 2011, respectively.

 

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NOTE 10 — 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 is determined by management of ARP and APL through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations. For derivatives qualifying as hedges, ARP and APL recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income and reclassify the portion relating to ARP’s commodity derivatives to gas and oil production revenues and gathering and processing revenues for APL’s commodity derivatives and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated combined statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, ARP and APL recognize changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated combined statements of operations as they occur.

Derivatives are recorded on the Partnership’s consolidated combined balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated combined balance sheets of $102.6 million and $46.4 million at June 30, 2012 and December 31, 2011, respectively. Of the $22.2 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated combined balance sheet related to derivatives at June 30, 2012, if the fair values of the instruments remain at current market values, the Partnership will reclassify $8.1 million of gains to its consolidated combined statement of operations over the next twelve month period as these contracts expire, consisting of $8.4 million of gains to gas and oil production revenues and $0.3 million of losses to gathering and processing revenues. Aggregate gains of $14.1 million to gas and oil production revenues will be reclassified to the Partnership’s consolidated combined statements of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

Atlas Resource Partners

ARP enters 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 combined 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 combined balance sheets as the initial value of the options. 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 combined balance sheets for the periods indicated (in thousands):

 

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Table of Contents

Offsetting Derivative Assets

   Gross Amounts
of Recognized
Assets
    Gross
Amounts
Offset in the
Consolidated
Combined
Balance Sheets
    Net Amount of Assets
Presented in the
Consolidated Combined
Balance Sheets
 

As of June 30, 2012

      

Current portion of derivative assets

   $ 17,098      $ (971   $ 16,127   

Long-term portion of derivative assets

     24,177        (4,623     19,554   

Long-term portion of derivative liabilities

     26        (26     —     
  

 

 

   

 

 

   

 

 

 

Total derivative assets

   $ 41,301      $ (5,620   $ 35,681   
  

 

 

   

 

 

   

 

 

 

As of December 31, 2011

      

Current portion of derivative assets

   $ 14,146      $ (345   $ 13,801   

Long-term portion of derivative assets

     21,485        (5,357     16,128   
  

 

 

   

 

 

   

 

 

 

Total derivative assets

   $ 35,631      $ (5,702   $ 29,929   
  

 

 

   

 

 

   

 

 

 

Offsetting Derivative Liabilities

   Gross Amounts
of Recognized
Liabilities
    Gross
Amounts
Offset in the
Consolidated
Combined
Balance Sheets
    Net Amount of Liabilities
Presented in the
Consolidated Combined
Balance Sheets
 

As of June 30, 2012

      

Current portion of derivative assets

   $ (971   $ 971      $ —     

Long-term portion of derivative assets

     (4,623     4,623        —     

Long-term portion of derivative liabilities

     (154     26        (128
  

 

 

   

 

 

   

 

 

 

Total derivative liabilities

   $ (5,748   $ 5,620      $ (128
  

 

 

   

 

 

   

 

 

 

As of December 31, 2011

      

Current portion of derivative liabilities

   $ (345   $ 345      $ —     

Long-term portion of derivative liabilities

     (5,357     5,357        —     
  

 

 

   

 

 

   

 

 

 

Total derivative liabilities

   $ (5,702   $ 5,702      $ —     
  

 

 

   

 

 

   

 

 

 

The following table summarizes ARP’s gain or loss recognized in the Partnership’s consolidated combined statements of operations for effective derivative instruments for the periods indicated (in thousands):

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2012     2011     2012     2011  

Gain (loss) recognized in accumulated OCI

   $ (514   $ 6,407      $ 13,655      $ 6,849   

Gain reclassified from accumulated OCI into income

   $ (6,739   $ (1,578   $ (9,339   $ (9,309

ARP enters 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. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

In March 2012, ARP entered into contracts which provided the option to enter into swap contracts (“swaptions”) up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 4). In connection with the swaption contracts, ARP paid premiums of $4.6 million, which represented the fair value of contracts on the date of the transaction and was initially recorded as a derivative asset on the Partnership’s consolidated combined balance sheet and was fully amortized as of June 30, 2012. For the three and six months ended June 30, 2012, ARP recorded approximately $3.6 million and $4.6 million, respectively, of amortization expense in other, net on the Partnership’s consolidated combined statements of operations related to the swaption contracts.

 

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Table of Contents

In June 2012, ARP received approximately $3.9 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 9). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income and will be reclassified into the Partnership’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

ARP recognized gains of $6.7 million and $1.6 million for the three months ended June 30, 2012 and 2011, respectively, and $9.3 million for both the six months ended June 30, 2012 and 2011 on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in ARP’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and six months ended June 30, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At June 30, 2012, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

 

                            

Asset/(Liability)

 

Production

Period Ending

             Volumes      Average
Fixed Price
     Fair Value
Asset
 

December 31,

               (mmbtu)(1)      (per mmbtu)(1)      (in thousands)(2)  

2012

           9,060,000       $ 3.550       $ 5,347   

2013

           11,160,000       $ 4.076         5,499   

2014

           10,800,000       $ 4.373         4,569   

2015

           7,350,000       $ 4.430         2,135   
              

 

 

 
               $ 17,550   
              

 

 

 

Natural Gas Costless Collars

 

Production

Period Ending

       

Option Type

   Volumes      Average
Floor and Cap
     Fair Value
Asset/(Liability)
 

December 31,

             (mmbtu)(1)      (per mmbtu)(1)      (in thousands)(2)  

2012

      Puts purchased      2,160,000       $ 4.074       $ 2,506   

2012

      Calls sold      2,160,000       $ 5.279         (22

2013

      Puts purchased      5,520,000       $ 4.395         5,768   

2013

      Calls sold      5,520,000       $ 5.443         (538

2014

      Puts purchased      3,840,000       $ 4.221         3,004   

2014

      Calls sold      3,840,000       $ 5.120         (1,072

2015

      Puts purchased      3,480,000       $ 4.234         2,903   

2015

      Calls sold      3,480,000       $ 5.129         (1,594
              

 

 

 
               $ 10,955   
              

 

 

 

Natural Gas Put Options

 

                            

Asset/(Liability)

 

Production

Period Ending

       

Option Type

   Volumes      Average Fixed
Price
     Fair Value
Asset
 

December 31,

              (mmbtu)(1)      (per mmbtu)(1)      (in thousands)(2)  

2012

      Puts purchased      2,940,000       $ 2.802       $ 522   

2013

      Puts purchased      3,180,000       $ 3.450         1,262   

2014

      Puts purchased      1,800,000       $ 3.800         933   

2015

      Puts purchased      1,440,000       $ 4.000         978   

2016

      Puts purchased      1,440,000       $ 4.150         1,178   
              

 

 

 
               $ 4,873   
              

 

 

 

 

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Table of Contents

Crude Oil Fixed Price Swaps

 

Production                Average      Fair Value  
Period Ending         Volumes      Fixed Price      Asset  

December 31,

        (Bbl)(1)      (per Bbl)(1)      (in thousands)(3)  

2012

        13,500       $ 103.804       $ 286   

2013

        18,600       $ 100.669         227   

2014

        36,000       $ 97.693         355   

2015

        45,000       $ 89.504         114   
           

 

 

 
            $ 982   
           

 

 

 

Crude Oil Costless Collars

 

Production

Period Ending

        Volumes      Average
Floor and  Cap
     Fair Value
Asset/(Liability)
 

December 31,

  

Option Type

   (Bbl)(1)      (per Bbl)(1)      (in thousands)(3)  

2012

   Puts purchased      30,000       $ 90.000       $ 274   

2012

   Calls sold      30,000       $ 117.912         (18

2013

   Puts purchased      60,000       $ 90.000         693   

2013

   Calls sold      60,000       $ 116.396         (173

2014

   Puts purchased      41,160       $ 84.169         471   

2014

   Calls sold      41,160       $ 113.308         (217

2015

   Puts purchased      29,250       $ 83.846         365   

2015

   Calls sold      29,250       $ 110.654         (202
           

 

 

 
            $ 1,193   
           

 

 

 

Total ARP net asset

         $ 35,553   
           

 

 

 

 

(1) 

“Mmbtu” represents million British Thermal Units; “Bbl” represents barrels.

(2) 

Fair value based on forward NYMEX natural gas prices, as applicable.

(3) 

Fair value based on forward WTI crude oil prices, as applicable.

Prior to its merger with Chevron on February 17, 2011, AEI monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business (see Note 3). AEI also monetized derivative instruments which were specifically related to the future natural gas and oil production of the limited partners of the Drilling Partnerships. At June 30, 2012, remaining hedge monetization cash proceeds of $20.2 million related to the amounts hedged on behalf of the Drilling Partnerships’ limited partners were included within cash and cash equivalents on the Partnership’s consolidated balance sheet, and ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated combined balance sheets as of June 30, 2012 and December 31, 2011.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At June 30, 2012, net unrealized derivative assets of $4.2 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 June 30, 2012 and December 31, 2011 were included in the Partnership’s consolidated combined balance sheets as follows (in thousands):

 

     June 30,     December 31,  
     2012     2011  

Current portion of derivative payable to Drilling Partnerships:

    

Hedge monetization proceeds

   $ (15,210   $ (20,900

Hedge contracts covering future natural gas production

     (670     —     

Long-term portion of derivative payable to Drilling Partnerships:

    

Hedge monetization proceeds

     (4,975     (15,272

Hedge contracts covering future natural gas production

     (3,533     —     
  

 

 

   

 

 

 
   $ (24,388   $ (36,172
  

 

 

   

 

 

 

 

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Table of Contents

At June 30, 2012, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships will have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its senior secured credit facility (see Note 9), 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. ARP, as general partner of the Drilling Partnerships, will administer the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

Atlas Pipeline Partners

For the three and six months ended June 30, 2012 and 2011, APL did not apply hedge accounting for derivatives. As such, changes in fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations. The change in fair value of commodity-based derivative instruments entered into prior to the discontinuation of hedge accounting will be reclassified from within accumulated other comprehensive income on the Partnership’s consolidated combined balance sheets to gathering and processing revenue on the Partnership’s consolidated combined statements of operations at the time the originally hedged physical transactions settle.

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 combined balance sheets for the periods indicated (in thousands):

 

Offsetting of Derivative Assets

   Gross
Amounts of
Recognized
Assets
    Gross
Amounts
Offset in the
Consolidated
Combined
Balance Sheets
    Net Amounts of
Assets  Presented in
the Consolidated
Combined Balance
Sheets
 

As of June 30, 2012

      

Current portion of derivative assets

   $ 38,366      $ (1,023   $ 37,343   

Long-term portion of derivative assets

     30,098        (419     29,679   
  

 

 

   

 

 

   

 

 

 

Total derivative assets

   $ 68,464      $ (1,442   $ 67,022   
  

 

 

   

 

 

   

 

 

 

As of December 31, 2011

      

Current portion of derivative assets

   $ 11,603      $ (9,958   $ 1,645   

Long-term portion of derivative assets

     17,011        (2,197     14,814   
  

 

 

   

 

 

   

 

 

 

Total derivative assets

   $ 28,614      $ (12,155   $ 16,459   
  

 

 

   

 

 

   

 

 

 

Offsetting of Derivative Liabilities

   Gross
Amounts of
Recognized
Liabilities
    Gross
Amounts
Offset in the
Consolidated
Combined
Balance Sheets
    Net Amounts of
Liabilities Presented
in the Consolidated
Combined Balance
Sheets
 

As of June 30, 2012

      

Current portion of derivative liabilities

   $ (1,023   $ 1,023      $ —     

Long-term portion of derivative liabilities

     (419     419        —     
  

 

 

   

 

 

   

 

 

 

Total derivative liabilities

   $ (1,442   $ 1,442      $ —     
  

 

 

   

 

 

   

 

 

 

As of December 31, 2011

      

Current portion of derivative liabilities

   $ (9,958   $ 9,958      $ —     

Long-term portion of derivative liabilities

     (2,197     2,197        —     
  

 

 

   

 

 

   

 

 

 

Total derivative liabilities

   $ (12,155   $ 12,155      $ —     
  

 

 

   

 

 

   

 

 

 

 

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Table of Contents

As of June 30, 2012, APL had the following commodity derivatives:

Fixed Price Swaps

 

     Purchased/                  Average
Fixed
    

Fair Value(1)

Asset/(Liability)

 

Production Period

   Sold      Commodity    Volumes(2)      Price      (in thousands)  

Natural Gas

              

2012

     Sold       Natural Gas      2,460,000       $ 3.117       $ 415   

2013

     Sold       Natural Gas      1,200,000       $ 3.476         (59

2014

     Sold       Natural Gas      5,400,000       $ 3.903         (228

NGLs

              

2012

     Sold       Propane      10,080,000       $ 1.300         4,546   

2012

     Sold       Normal Butane      2,646,000       $ 1.709         1,103   

2012

     Sold       Isobutane      1,512,000       $ 1.577         203   

2012

     Sold       Natural Gasoline      2,142,000       $ 2.393         1,598   

2013

     Sold       Propane      46,368,000       $ 1.257         17,654   

2013

     Sold       Normal Butane      2,394,000       $ 1.662         805   

2013

     Sold       Isobutane      1,134,000       $ 1.807         370   

2014

     Sold       Propane      630,000       $ 1.268         210   

Crude Oil

              

2012

     Sold       Crude Oil      144,000       $ 96.093         1,447   

2013

     Sold       Crude Oil      345,000       $ 97.170         3,032   

2014

     Sold       Crude Oil      60,000       $ 98.425         626   
              

 

 

 

Total Fixed Price Swaps

               $ 31,722   
              

 

 

 

Options

 

Production    Purchased/                       

Average

Strike

    

Fair Value(1)

Asset/(Liability)

 

Period

   Sold     Type      Commodity    Volumes(2)      Price      (in thousands)  

NGLs

                

2012

     Purchased        Put       Propane      15,750,000       $ 1.362         8,070   

2012

     Purchased        Put       Normal Butane      4,032,000       $ 1.550         1,094   

2012

     Purchased        Put       Isobutane      2,142,000       $ 1.577         451   

2012

     Purchased        Put       Natural Gasoline      7,812,000       $ 1.997         2,005   

2013

     Purchased        Put       Normal Butane      10,458,000       $ 1.667         4,172   

2013

     Purchased        Put       Isobutane      4,158,000       $ 1.687         1,529   

2013

     Purchased        Put       Natural Gasoline      23,940,000       $ 2.108         9,156   

Crude Oil

                

2012

     Sold (3)      Call       Crude Oil      249,000       $ 94.694         (663

2012

     Purchased (3)      Call       Crude Oil      90,000       $ 125.200         14   

2012

     Purchased        Put       Crude Oil      78,000       $ 106.180         1,618   

2013

     Purchased        Put       Crude Oil      282,000       $ 100.100         4,799   

2014

     Purchased        Put       Crude Oil      136,500       $ 104.750         3,055   
                

 

 

 

Total Options

                 $ 35,300   
                

 

 

 

Total APL net asset

                 $ 67,022   
                

 

 

 

 

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(1)

See Note 11 for discussion on fair value methodology.

(2) 

Volumes for natural gas are stated in MMBTU's. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels.

(3)

Calls purchased for 2012 represent offsetting positions for calls sold as part of costless collars. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

The following tables summarize the gross effect of APL’s derivative instruments on the Partnership’s consolidated combined statement of operations for the period indicated (in thousands):

 

     Three Months
Ended June 30,
    Six Months
Ended June 30,
 
     2012     2011     2012     2011  

Derivatives previously designated as cash flow hedges

        

Loss reclassified from accumulated other comprehensive loss into natural gas and liquids sales

   $ (1,108   $ (1,702   $ (2,254   $ (3,404
  

 

 

   

 

 

   

 

 

   

 

 

 

Derivatives not designated as hedges

        

Gain (loss) recognized in gain (loss) on mark-to-market derivatives

        

Commodity contract—realized(1)

     3,685        (6,236     2,922        (8,793

Commodity contract—unrealized(2)

     64,162        13,073        52,890        (6,015
  

 

 

   

 

 

   

 

 

   

 

 

 

Gain (loss) on mark-to-market derivatives

   $ 67,847      $ 6,837      $ 55,812      $ (14,808
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(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 combined balance sheets was as follows (in thousands):

 

     June 30,     December 31,  
     2012     2011  

Current portion of derivative asset

   $ 53,470      $ 15,447   

Long-term derivative asset

     49,233        30,941   

Current portion of derivative liability

     —          —     

Long-term derivative liability

     (128     —     
  

 

 

   

 

 

 

Total Partnership net asset

   $ 102,575      $ 46,388   
  

 

 

   

 

 

 

NOTE 11 – 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.

 

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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 10). 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 the NYMEX quoted prices for futures and options contracts traded on NYMEX 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 a Level 3 input. 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.

Information for ARP’s and APL’s assets and liabilities measured at fair value at June 30, 2012 and December 31, 2011 was as follows (in thousands):

 

     Level 1      Level 2     Level 3      Total  

As of June 30, 2012

          

Derivative assets, gross

          

ARP Commodity swaps

   $ —         $ 20,445      $ —         $ 20,445   

ARP Commodity puts

     —           4,872        —           4,872   

ARP Commodity options

     —           15,984        —           15,984   

APL Commodity swaps

     —           6,012        26,489         32,501   

APL Commodity options

     —           9,486        26,477         35,963   
  

 

 

    

 

 

   

 

 

    

 

 

 

Total derivative assets, gross

     —           56,799        52,966         109,765   
  

 

 

    

 

 

   

 

 

    

 

 

 

Derivative liabilities, gross

          

ARP Commodity swaps

     —           (1,913     —           (1,913

ARP Commodity puts

     —           —          —           —     

ARP Commodity options

     —           (3,835     —           (3,835

APL Commodity swaps

     —           (779     —           (779

APL Commodity options

     —           (663     —           (663
  

 

 

    

 

 

   

 

 

    

 

 

 

Total derivative liabilities, gross

     —           (7,190     —           (7,190
  

 

 

    

 

 

   

 

 

    

 

 

 

Total derivatives, fair value, net

   $ —         $ 49,609      $ 52,966       $ 102,575   
  

 

 

    

 

 

   

 

 

    

 

 

 

As of December 31, 2011

          

Derivative assets, gross

          

ARP Commodity swaps

   $ —         $ 20,908      $ —         $ 20,908   

ARP Commodity puts

     —           —          —           —     

ARP Commodity options

     —           14,723        —           14,723   

APL Commodity swaps

     —           1,270        1,836         3,106   

APL Commodity options

     —           7,229        18,279         25,508   
  

 

 

    

 

 

   

 

 

    

 

 

 

Total derivative assets, gross

     —           44,130        20,115         64,245   
  

 

 

    

 

 

   

 

 

    

 

 

 

 

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Table of Contents

Derivative liabilities, gross

         

ARP Commodity swaps

     —           —          —          —     

ARP Commodity puts

     —           —          —          —     

ARP Commodity options

     —           (5,702     —          (5,702

APL Commodity swaps

     —           (2,766     (3,569     (6,335

APL Commodity options

     —           (5,820     —          (5,820
  

 

 

    

 

 

   

 

 

   

 

 

 

Total derivative liabilities, gross

     —           (14,288     (3,569     (17,857
  

 

 

    

 

 

   

 

 

   

 

 

 

Total derivatives, fair value, net

   $ —         $ 29,842      $ 16,546      $ 46,388   
  

 

 

    

 

 

   

 

 

   

 

 

 

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 six months ended June 30, 2012 (in thousands):

 

     NGL Fixed Price Swaps     NGL Put Options     Total  
     Volume(1)     Amount     Volume(1)     Amount     Amount  

Balance – January 1, 2012

     49,644      $ (1,733     92,610      $ 18,279      $ 16,546   

New contracts(2)

     47,754        —          —          —          —     

Cash settlements from unrealized gain (loss)(3)(4)

     (30,492     (2,852     (24,318     108        (2,744

Net change in unrealized gain (loss)(3)

     —          31,074        —          13,285        44,359   

Option premium recognition(4)

     —          —          —          (5,195     (5,195
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance – June 30, 2012

     66,906      $ 26,489        68,292      $ 26,477      $ 52,966   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Volumes are stated in thousand gallons.

(2)

Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade.

(3) 

Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated combined statements of operations.

(4) 

Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration.

The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at June 30, 2012 and December 31, 2011 (in thousands):

 

     Gallons      Third  Party
Quotes(1)
    Adjustments(2)     Total
Amount
 

As of June 30, 2012

         

Propane swaps

     57,078       $ 22,755      $ (345   $ 22,410   

Isobutane swaps

     2,646         174        399        573   

Normal butane swaps

     5,040         1,872        36        1,908   

Natural gasoline swaps

     2,142         1,893        (295     1,598   
  

 

 

    

 

 

   

 

 

   

 

 

 

Total NGL swaps – June 30, 2012

     66,906       $ 26,694      $ (205   $ 26,489   
  

 

 

    

 

 

   

 

 

   

 

 

 

As of December 31, 2011

         

Ethane swaps

     6,678       $ 31      $ —        $ 31   

Propane swaps

     29,358         (1,322     —          (1,322

Isobutane swaps

     2,646         (1,590     570        (1,020

Normal butane swaps

     6,804         (1,074     343        (731

Natural gasoline swaps

     4,158         1,824        (515     1,309   
  

 

 

    

 

 

   

 

 

   

 

 

 

Total NGL swaps – December 31, 2011

     49,644       $ (2,131   $ 398      $ (1,733
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap.
(2) Based upon the price adjustment to the price provided by the third party to adjust for product and location differentials. The adjustment is calculated through a regression model comparing settlement prices of the different products and locations over a three year historical period.

 

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The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for APL’s NGL swaps for the periods indicated (in thousands):

 

     Level 3 Fair     Adjustment based upon Regression
Coefficient
 
     Value
Adjustments
    Lower
95%
     Upper
95%
     Average
Coefficient
 

As of June 30, 2012

          

Propane swaps

   $ (345     0.9100         0.9204         0.9152   

Isobutane swaps

     399        1.1195         1.1285         1.1240   

Normal butane swaps

     36        0.9926         1.0194         1.0060   

Natural gasoline swaps

     (295     0.9028         0.9149         0.9089   
  

 

 

         

Total NGL swaps – June 30, 2012

   $ (205        
  

 

 

         

As of December 31, 2011

          

Isobutane swaps

   $ 570        1.1239         1.1333         1.1286   

Normal butane swaps

     343        1.0311         1.0355         1.0333   

Natural gasoline swaps

     (515     0.9351         0.9426         0.9389   
  

 

 

         

Total NGL swaps – December 31, 2011

   $ 398           
  

 

 

         

APL had $6.3 million and $11.5 million of NGL linefill at June 30, 2012 and December 31, 2011, respectively, which was included within prepaid expenses and other on the Partnership’s consolidated combined 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 $0.5 million and $0.8 million as of June 30, 2012 and December 31, 2011, respectively.

The following table provides a summary of changes in fair value of APL’s NGL linefill for the six months ended June 30, 2012 (in thousands):

 

     NGL Linefill  
     Gallons     Amount  

Balance – December 31, 2011

     10,408      $ 11,529   

Cash settlements

     (2,520     (2,698

Net change in NGL linefill valuation(1)

     —          (2,495
  

 

 

   

 

 

 

Balance – June 30, 2012

     7,888      $ 6,336   
  

 

 

   

 

 

 

 

(1) Included within gathering and processing revenues on the Partnership’s consolidated combined 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 combined balance sheets are 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 June 30, 2012 and December 31, 2011, which consist principally of APL’s Senior Notes and borrowings under ARP’s and APL’s revolving credit facilities, were $878.3 million and $537.3 million, respectively, compared with the carrying amounts of $857.0 million and $524.1 million, respectively. The carrying value of outstanding borrowings under the respective credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value and thus are categorized as Level 1. The fair value of the APL Senior Notes is provided by financial institutions based on its recent trading activity and is therefore categorized as Level 3.

 

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Table of Contents

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 8). Information for assets that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2012 and 2011 were as follows (in thousands):

 

     Three Months Ended June 30,  
     2012      2011  
     Level 3      Total      Level 3      Total  

Asset retirement obligations

   $ 3,911       $ 3,911       $ —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 3,911       $ 3,911       $ —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 
     Six Months Ended June 30,  
     2012      2011  
     Level 3      Total      Level 3      Total  

Asset retirement obligations

   $ 4,092       $ 4,092       $ 93       $ 93   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 4,092       $ 4,092       $ 93       $ 93   
  

 

 

    

 

 

    

 

 

    

 

 

 

ARP and APL estimate the fair value of their long-lived assets by reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the year ended December 31, 2011, ARP recognized a $7.0 million impairment of long-lived assets, which was defined as a Level 3 fair value measurement (see Note 2 – Impairment of Long-Lived Assets). No impairments were recognized for the three and six months ended June 30, 2012 and 2011 (see Note 6).

In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 8). These inputs require significant judgments and estimates by ARP’s management at the time of the valuation and are subject to change.

In February 2012, APL acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts (“Trigger Payments”), if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the Trigger Payments recognized upon acquisition was a $6.0 million current liability, which was recorded within accrued liabilities on the Partnership’s consolidated combined balance sheets and a $6.0 million long-term liability, which was recorded within asset retirement obligations and other on the Partnership’s consolidated combined balance sheets. The initial recording of the transaction was based upon preliminary valuation assessments and is subject to change. The range of the undiscounted amounts APL could pay related to the Trigger Payments is between $0 and $12.0 million.

NOTE 12 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ARP’s Sponsored Investment Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

 

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Table of Contents

ARP’s Joint Venture Agreement with Subsidiaries of Equal Energy, Ltd. In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under ARP’s revolving credit facility (see Note 9). Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP serves as the drilling and completion operator, while Equal will undertake production operations, including water disposal. Subsequent to the formation of the joint venture, each party can contribute acreage to the joint venture through the establishment of an area of mutual interest closely surrounding Equal’s existing acreage position. ARP proportionately consolidates its 50% ownership interest in the joint venture.

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, the management of ARP believes that any liability incurred would not be material. Also, ARP has agreed to subordinate a portion of its share of net partnership revenues from the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to seven years, in accordance with the terms of the partnership agreements. For the three months ended June 30, 2012 and 2011, $1.4 million and $1.3 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships. For the six months ended June 30, 2012 and 2011, $1.8 million and $2.7 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

Immediately following the acquisition of the Transferred Business, the Partnership received from Chevron $118.7 million related to a contractual cash transaction adjustment related to certain liabilities of the Transferred Business at February 17, 2011. Following the closing of the acquisition of the Transferred Business, the Partnership entered into a reconciliation process with Chevron to determine the final cash adjustment amount pursuant to the transaction agreement. The reconciliation process was assumed by ARP on March 5, 2012 and remains ongoing at June 30, 2012, as certain amounts included within the contractual cash transaction adjustment are in dispute between the parties. ARP believes the amounts included within the contractual cash transaction adjustment are appropriate and is currently engaged in an on-going reconciliation process with Chevron. The resolution of the disputed amounts could result in ARP being required to repay a portion of the cash transaction adjustment (see Note 3). According to the transaction agreement, should ARP and Chevron not be able to come to an agreement during the reconciliation process, the two parties will enter into arbitration with a neutral public accounting firm. At June 30, 2012, the Partnership believes the range of loss associated with the disputed balances is between zero and $45.0 million.

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, consisting primarily of 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 $2.5 million and $2.4 million for three months ended June 30, 2012 and 2011, respectively, and $5.0 million and $4.9 million for six months ended June 30, 2012 and 2011, respectively. The future fixed and determinable portion of APL’s obligations as of June 30, 2012 was as follows: remainder of 2012—$4.1 million; 2013—$8.2 million; and 2014—$6.1 million.

As of June 30, 2012, ARP and APL are committed to expend approximately $108.7 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

The Partnership and its subsidiaries are 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.

 

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Table of Contents

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 combined balance sheets rather than as income on its consolidated combined statements of operations. These gains represent the Partnership’s portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.

In February 2011, the Partnership paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on the Partnership’s common limited partner unit’s February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million (see Note 3).

Atlas Resource Partners

On April 30, 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for gross proceeds of $120.6 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 Securities and Exchange Commission by October 30, 2012 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by December 31, 2012. If ARP does not meet the aforementioned deadline for the common units to be declared effective, the common unit holders subject to the registration rights agreement will receive liquidated damages of 0.50% of the gross proceeds from the private placement, or $0.6 million, for the first 30-day period after December 31, 2012, increasing by an additional 0.50% per 30-day period thereafter, up to a maximum of 2.0% of the gross proceeds of the private placement per 30-day period. On July 11, 2012, ARP filed a registration statement with the Securities and Exchange Commission for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. In connection with the private placement of common units, the Partnership recorded an $11.2 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated combined balance sheet at June 30, 2012.

In February 2012, the board of directors of the Partnership’s general partner approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to the Partnership’s unitholders using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of these limited partner units represented approximately 20.0% of the common limited partner units outstanding (see Note 1).

Atlas Pipeline Partners

In February 2011, as part of AEI’s merger with Chevron, the APL Class C Preferred Units were acquired from AEI by Chevron. On May 27, 2011, APL redeemed all 8,000 APL Class C Preferred Units outstanding for cash at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividend on the 8,000 APL Class C Preferred Units prior to APL’s redemption. Subsequent to the redemption, APL had no preferred units outstanding.

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, 2011 through June 30, 2012 were as follows (in thousands, except per unit amounts):

 

Date Cash

Distribution Paid

   For Quarter
Ended
   Cash Distribution per
Common Limited
Partner Unit
     Total Cash Distributions
Paid to Common

Limited Partners
 

May 20, 2011

   March 31, 2011    $ 0.11       $ 5,635   

August 19, 2011

   June 30, 2011    $ 0.22       $ 11,276   

November 18, 2011

   September 30, 2011    $ 0.24       $ 12,303   

February 17, 2012

   December 31, 2011    $ 0.24       $ 12,307   

May 18, 2012

   March 31, 2012    $ 0.25       $ 12,830   

 

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On July 17, 2012, the Partnership declared a cash distribution of $0.25 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $12.8 million distribution will be paid on August 17, 2012 to unitholders of record at the close of business on August 7, 2012.

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 June 30, 2012 were as follows (in thousands, except per unit amounts):

 

Date Cash

Distribution

Paid

   For Quarter Ended    ARP Cash
Distribution
per Common
Limited
Partner Unit
    Total ARP  Cash
Distribution

to Common
Limited
Partners
     Total ARP  Cash
Distribution

to the
General Partner
 
                       (in thousands)  

May 15, 2012

   March 31, 2012    $ 0.12 (1)    $ 3,144       $ 64   

 

(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 June 28, 2012, ARP declared a cash distribution of $0.40 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $13.2 million distribution, including $0.3 million to the Partnership, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on July 12, 2012.

APL Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and general partner distributions declared by APL for the period from January 1, 2011 through June 30, 2012 were as follows (in thousands, except per unit amounts):

 

Date Cash

Distribution

Paid

   For Quarter Ended    APL Cash
Distribution
per Common
Limited
Partner Unit
     Total APL  Cash
Distribution

to Common
Limited
Partners
     Total APL  Cash
Distribution

to the
General
Partner
 

May 13, 2011

   March 31, 2011    $ 0.40       $ 21,400       $ 439   

August 12, 2011

   June 30, 2011    $ 0.47       $ 25,184       $ 967   

November 14, 2011

   September 30, 2011    $ 0.54       $ 28,953       $ 1,844   

February 14, 2012

   December 31, 2011    $ 0.55       $ 29,489       $ 2,031   

May 15, 2012

   March 31, 2012    $ 0.56       $ 30,030       $ 2,217   

On July 17, 2012, APL declared a cash distribution of $0.56 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended June 30, 2012. The $32.3 million distribution, including $2.2 million to the Partnership, as general partner, will be paid on August 14, 2012 to unitholders of record at the close of business on August 7, 2012.

 

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Table of Contents

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 June 30, 2012, the Partnership had 4,646,139 phantom units and unit options outstanding under the 2010 LTIP, with 1,110,416 phantom units and unit options available for grant.

Upon a change in control, as defined in the 2010 LTIP, all unvested awards held by directors will immediately vest in full. In the case of awards held by eligible employees, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), in any case following a change in control, any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option.

In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership’s general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

 

   

cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

 

   

accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the Partnership’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

 

   

provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

 

   

terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

 

   

make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate.

2010 Phantom Units. A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. Through June 30, 2012, phantom units granted under the 2010 LTIP generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant. Of the phantom units outstanding under the 2010 LTIP at June 30, 2012, there are 4,078 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at June 30, 2012 include DERs. During the three and six months ended June 30, 2012, the Partnership paid $0.5 million and $1.0 million, respectively, with respect to the 2010 LTIP DERs. There was $0.2 million paid with respect to the 2010 LTIP DERs for the three and six months ended June 30, 2011.

The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:

 

     Three Months Ended June 30,  
     2012      2011  
     Number
of Units
    Weighted
Average
Grant
Date Fair
Value
     Number
of Units
     Weighted
Average
Grant
Date Fair
Value
 

Outstanding, beginning of period

     2,051,706      $ 20.46         1,566,000       $ 22.23   

Granted

     17,650        34.23         153,949         22.84   

Vested (1)

     —          —           —           —     

Forfeited

     (3,997     17.47         —           —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Outstanding, end of period(3)

     2,065,359      $ 20.58         1,719,949       $ 22.28   
  

 

 

   

 

 

    

 

 

    

 

 

 

Non-cash compensation expense recognized (in thousands)

  

  $ 2,884          $ 2,526   
    

 

 

       

 

 

 

 

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Table of Contents
     Six Months Ended June 30,  
     2012      2011  
     Number
of Units
    Weighted
Average
Grant
Date Fair
Value
     Number
of Units
     Weighted
Average
Grant
Date Fair
Value
 

Outstanding, beginning of year

     1,838,164      $ 22.11         —         $ —     

Granted

     72,950        28.49         1,719,949         22.28   

Vested (1)

     (7,226     20.67         —           —     

Forfeited

     (3,997     17.47         —           —     

ARP anti-dilution adjustment(2)

     165,468        —           —           —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Outstanding, end of period(3)

     2,065,359      $ 20.58         1,719,949       $ 22.28   
  

 

 

   

 

 

    

 

 

    

 

 

 

Non-cash compensation expense recognized (in thousands)

  

  $ 5,886          $ 2,702   
    

 

 

       

 

 

 

 

(1) The aggregate intrinsic values of phantom unit awards vested during the six months ended June 30, 2012 was $0.2 million. No phantom unit awards vested during the three months ended June 30, 2012 and 2011 and the six months ended June 30, 2011.
(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 June 30, 2012 was $63.0 million.

At June 30, 2012, the Partnership had approximately $29.0 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.

2010 Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also shall determine how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through June 30, 2012, unit options granted under the 2010 LTIP generally will vest 25% of the original granted amount three years from the date of grant and the remaining 75% of the original granted amount four years from the date of grant. There are 3,399 unit options outstanding under the 2010 LTIP at June 30, 2012 that will vest within the following twelve months.

The following table sets forth the 2010 LTIP unit option activity for the periods indicated:

 

     Three Months Ended June 30,  
     2012      2011  
     Number
of Unit
Options
    Weighted
Average
Exercise
Price
     Number
of Unit
Options
    Weighted
Average
Exercise
Price
 

Outstanding, beginning of period

     2,581,322      $ 20.45         2,226,000      $ 22.23   

Granted

     (271     17.47         26,500        25.45   

Forfeited

     (271     17.47         (10,000     22.23   
  

 

 

   

 

 

    

 

 

   

 

 

 

Outstanding, end of period(2)(3)

     2,580,780      $ 20.45         2,242,500      $ 22.27   
  

 

 

   

 

 

    

 

 

   

 

 

 

Options exercisable, end of period(4)

     —        $ —           —        $ —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Non-cash compensation expense recognized (in thousands)

  

  $ 1,573         $ 1,505   
    

 

 

      

 

 

 

 

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Table of Contents
     Six Months Ended June 30,  
     2012      2011  
     Number
of Unit
Options
    Weighted
Average
Exercise
Price
     Number
of Unit
Options
    Weighted
Average
Exercise
Price
 

Outstanding, beginning of year

     2,304,300      $ 22.12         —        $ —     

Granted

     68,958        26.31         2,252,500        22.27   

Forfeited

     (271     17.47         (10,000     22.23   

ARP anti-dilution adjustment(1)

     207,793        —           —          —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Outstanding, end of period(2)(3)

     2,580,780      $ 20.45         2,242,500      $ 22.27   
  

 

 

   

 

 

    

 

 

   

 

 

 

Options exercisable, end of period(4)

     —        $ —           —        $ —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Non-cash compensation expense recognized (in thousands)

  

  $ 3,134         $ 1,617   
    

 

 

      

 

 

 

 

(1) 

The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

(2)

The weighted average remaining contractual life for outstanding options at June 30, 2012 was 8.8 years.

(3)

The options outstanding at June 30, 2012 had an aggregate intrinsic value of $25.9 million.

(4)

No options were exercisable at June 30, 2012 or 2011. No options vested during the three and six months ended June 30, 2012 and 2011.

At June 30, 2012, the Partnership had approximately $15.4 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 June 30,
    Six Months Ended
June 30,
 
     2011     2012     2011  

Expected dividend yield

     1.5     3.7     1.5

Expected unit price volatility

     48.0     47.0     48.0

Risk-free interest rate

     2.5     1.4     2.8

Expected term (in years)

     6.88        6.88        6.88   

Fair value of unit options granted

   $ 11.01      $ 8.50      $ 9.94   

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 June 30, 2012, the Partnership had 997,233 phantom units and unit options outstanding under the 2006 LTIP, with 985,403 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.