10-Q 1 d531885d10q.htm FORM 10-Q 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 March 31, 2013

OR

 

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

For the transition period from                      to                     

Commission file number:1-4998

 

 

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

DELAWARE   23-3011077

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

Park Place Corporate Center One  
1000 Commerce Drive, 4th Floor  
Pittsburgh, Pennsylvania   15275-1011
(Address of principal executive office)   (Zip code)

Registrant’s telephone number, including area code :(877) 950-7473

 

 

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 a 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 common units of the registrant outstanding on May 2, 2013 was 76,918,206.

 

 

 


Table of Contents

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

 

         Page  
GLOSSARY OF TERMS   
PART I. FINANCIAL INFORMATION   

Item 1.

  Financial Statements      4   
  Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012 (Unaudited)      4   
  Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012 (Unaudited)      5   
 

Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2013 and 2012 (Unaudited)

     6   
  Consolidated Statement of Equity for the Three Months Ended March 31, 2013 (Unaudited)      7   
  Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012 (Unaudited)      8   
  Notes to Consolidated Financial Statements (Unaudited)      9   

Item 2.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      36   

Item 3.

  Quantitative and Qualitative Disclosures About Market Risk      55   

Item 4.

  Controls and Procedures      56   
PART II. OTHER INFORMATION      57   

Item 1A.

  Risk Factors      57   

Item 6.

  Exhibits      57   
SIGNATURES      60   

 

 

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Glossary of Terms

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:

 

BPD    Barrels per day. Barrel - measurement for a standard US barrel is 42 gallons. Crude oil and condensate are generally reported in barrels.
BTU    British thermal unit, a basic measure of heat energy
Condensate    Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.
EBITDA    Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.
FASB    Financial Accounting Standards Board
Fractionation    The process used to separate an NGL stream into its individual components.
GAAP    Generally Accepted Accounting Principles
G.P.    General Partner or General Partnership
GPM    Gallons per minute
Keep-Whole    Contract with producer whereby plant operator pays for or returns gas having an equivalent BTU content to the gas received at the well-head.
L.P.    Limited Partner or Limited Partnership
MCF    Thousand cubic feet
MCFD    Thousand cubic feet per day
MMBTU    Million British thermal units
MMCFD    Million cubic feet per day
NGL(s)    Natural gas liquid(s), primarily ethane, propane, normal butane, isobutane and natural gasoline
Percentage of Proceeds (“POP”)    Contract with natural gas producers whereby the plant operator retains a negotiated percentage of the sale proceeds.
Residue gas    The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.
SEC    Securities and Exchange Commission

 

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

     March 31,
2013
     December 31,
2012
 
ASSETS      

Current assets:

     

Cash and cash equivalents

   $ 8,261       $ 3,398   

Funds held in escrow

     25,001         25,000   

Accounts receivable

     162,556         157,526   

Current portion of derivative assets

     17,391         23,077   

Prepaid expenses and other

     11,905         11,074   
  

 

 

    

 

 

 

Total current assets

     225,114         220,075   

Property, plant and equipment, net

     2,299,967         2,200,381   

Goodwill

     319,285         319,285   

Intangible assets, net

     182,786         199,360   

Equity method investment in joint venture

     86,242         86,002   

Long-term portion of derivative assets

     2,378         7,942   

Other assets, net

     38,658         32,593   
  

 

 

    

 

 

 

Total assets

   $ 3,154,430       $ 3,065,638   
  

 

 

    

 

 

 
LIABILITIES AND EQUITY      

Current liabilities:

     

Current portion of long-term debt

   $ 8,861       $ 10,835   

Accounts payable – affiliates

     4,338         5,500   

Accounts payable

     71,703         59,308   

Accrued liabilities

     47,007         57,752   

Accrued interest payable

     5,474         10,399   

Current portion of derivative liability

     619         —     

Accrued producer liabilities

     114,057         109,725   
  

 

 

    

 

 

 

Total current liabilities

     252,059         253,519   

Long-term portion of derivative liability

     925         —     

Long-term debt, less current portion

     1,310,051         1,169,083   

Deferred income taxes, net

     30,249         30,258   

Other long-term liability

     6,358         6,370   

Commitments and contingencies

     

Equity:

     

Common limited partners’ interests

     1,456,911         1,507,676   

General Partner’s interest

     31,031         31,501   
  

 

 

    

 

 

 

Total partners’ capital

     1,487,942         1,539,177   

Non-controlling interest

     66,846         67,231   
  

 

 

    

 

 

 

Total equity

     1,554,788         1,606,408   
  

 

 

    

 

 

 

Total liabilities and equity

   $ 3,154,430       $ 3,065,638   
  

 

 

    

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

     Three Months Ended  
     March 31,  
     2013     2012  

Revenue:

    

Natural gas and liquids sales

   $ 383,848      $ 289,225   

Transportation, processing and other fees – third parties

     32,654        12,602   

Transportation, processing and other fees – affiliates

     71        79   

Derivative loss, net

     (12,083     (12,035

Other income, net

     3,422        2,415   
  

 

 

   

 

 

 

Total revenues

     407,912        292,286   
  

 

 

   

 

 

 

Costs and expenses:

    

Natural gas and liquids cost of sales

     325,540        233,105   

Plant operating

     21,271        13,881   

Transportation and compression

     588        264   

General and administrative

     12,548        9,070   

Compensation reimbursement – affiliates

     1,250        875   

Other costs

     530        (34

Depreciation and amortization

     30,458        20,842   

Interest

     18,686        8,708   
  

 

 

   

 

 

 

Total costs and expenses

     410,871        286,711   
  

 

 

   

 

 

 

Equity income in joint venture

     2,040        896   

Loss on early extinguishment of debt

     (26,582     —     
  

 

 

   

 

 

 

Income (loss) before tax

     (27,501     6,471   

Income tax benefit

     (9     —     
  

 

 

   

 

 

 

Net income (loss)

     (27,492     6,471   

Income attributable to non-controlling interests

     (1,369     (1,536
  

 

 

   

 

 

 

Net income (loss) attributable to common limited partners and the General Partner

   $ (28,861   $ 4,935   
  

 

 

   

 

 

 

Allocation of net income (loss) attributable to:

    

Common limited partner interest

   $ (31,206   $ 3,467   

General Partner interest

     2,345        1,468   
  

 

 

   

 

 

 
   $ (28,861   $ 4,935   
  

 

 

   

 

 

 

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

    

Basic

   $ (0.48   $ 0.06   
  

 

 

   

 

 

 

Weighted average common limited partner units (basic)

     64,646        53,620   
  

 

 

   

 

 

 

Diluted

   $ (0.48   $ 0.06   
  

 

 

   

 

 

 

Weighted average common limited partner units (diluted)

     64,646        54,013   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(Unaudited)

 

     Three Months Ended March 31,  
     2013     2012  

Net income (loss)

   $ (27,492   $ 6,471   

Income attributable to non-controlling interests

     (1,369     (1,536
  

 

 

   

 

 

 

Net income (loss) attributable to common limited partners and the General Partner

     (28,861     4,935   

Other comprehensive income:

    

Adjustment for realized losses on cash flow commodity based derivatives reclassified to net income

     —          1,146   
  

 

 

   

 

 

 

Comprehensive income (loss)

   $ (28,861   $ 6,081   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2013

(in thousands, except unit data)

(Unaudited)

 

     Number of
Limited
Partner
Common
Units
     Common
Limited
Partners
    General
Partner
    Non-
controlling
Interest
    Total  

Balance at December 31, 2012

     64,556,010       $ 1,507,676      $ 31,501      $ 67,231      $ 1,606,408   

Issuance of units and General Partner capital contribution

     447,785         14,144        302        —          14,446   

Issuance of common units under incentive plans

     1,911         63        —          —          63   

Unissued common units under incentive plans

     —           4,287        —          —          4,287   

Distributions paid

     —           (38,053     (3,117     —          (41,170

Distributions received from non-controlling interests

     —           —          —          26        26   

Decrease in non-controlling interest due to business combination

     —           —          —          (1,780     (1,780

Net income (loss)

     —           (31,206     2,345        1,369        (27,492
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance at March 31, 2013

     65,005,706       $ 1,456,911      $ 31,031      $ 66,846      $ 1,554,788   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

     Three Months Ended  
     March 31,  
     2013     2012  

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net income (loss)

   $ (27,492   $ 6,471   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

Depreciation and amortization

     30,458        20,842   

Equity income in joint venture

     (2,040     (896

Distributions received from equity method joint venture

     1,800        1,800   

Non-cash compensation expense

     4,384        978   

Amortization of deferred finance costs

     1,544        1,165   

Loss on early extinguishment of debt

     26,582        —     

Deferred income tax benefit

     (9     —     

Change in operating assets and liabilities, net of business combinations:

    

Accounts receivable, prepaid expenses and other

     (7,211     13,589   

Accounts payable and accrued liabilities

     (4,392     (16,075

Accounts payable and accounts receivable – affiliates

     (1,162     426   

Derivative accounts payable and receivable

     12,794        14,447   
  

 

 

   

 

 

 

Net cash provided by operating activities

     35,256        42,747   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Capital expenditures

     (108,516     (81,167

Cash paid for business combinations, net of cash received

     —          (17,235

Other

     126        126   
  

 

 

   

 

 

 

Net cash used in investing activities

     (108,390     (98,276
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Borrowings under credit facility

     278,000        319,500   

Repayments under credit facility

     (416,500     (231,500

Net proceeds from issuance of long term debt

     637,090        —     

Repayment of debt

     (365,822     —     

Payment of premium on retirement of debt

     (25,562     —     

Payment of deferred financing costs

     (99     (33

Principal payments on capital lease

     (2,135     (539

Net proceeds from issuance of common limited partner units

     14,144        —     

General Partner capital contributions

     302        —     

Net distributions received from non-controlling interest holders

     26        38   

Distributions paid to common limited partners and the General Partner

     (41,170     (31,737

Other

     (277     (200
  

 

 

   

 

 

 

Net cash provided by financing activities

     77,997        55,529   
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     4,863        —     

Cash and cash equivalents, beginning of period

     3,398        168   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 8,261      $ 168   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2013

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Pipeline Partners, L.P. (the “Partnership”) is a publicly-traded (NYSE: APL) Delaware limited partnership engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and the transportation of NGLs in the southwestern region of the United States. The Partnership’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”), a wholly-owned subsidiary of the Partnership. At March 31, 2013, Atlas Pipeline Partners GP, LLC (the “General Partner”) owned a combined 2.0% general partner interest in the consolidated operations of the Partnership, through which it manages and effectively controls both the Partnership and the Operating Partnership. The General Partner is a wholly-owned subsidiary of Atlas Energy, L.P. (“ATLS”), a publicly-traded limited partnership (NYSE: ATLS). The remaining 98.0% ownership interest in the consolidated operations consists of limited partner interests. At March 31, 2013, the Partnership had 65,005,706 common units outstanding, including 1,641,026 common units held by the General Partner and 4,113,227 common units held by ATLS.

The accompanying consolidated financial statements, which are unaudited, except the balance sheet at December 31, 2012, which is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. The results of operations for the three month period ended March 31, 2013 may not necessarily be indicative of the results of operations for the full year ending December 31, 2013.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Partnership’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its Annual Report on Form 10-K for the year ended December 31, 2012.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and for the Partnership only include changes in the fair value of unsettled derivative contracts which were previously accounted for as cash flow hedges (see Note 9). During the three months ended March 31, 2012, the Partnership reclassified $1.1 million from other comprehensive income to natural gas and liquids sales within the Partnership’s consolidated statements of operations. As of January 1, 2013, all amounts had been reclassified out of other comprehensive income and the Partnership had no amounts outstanding within other comprehensive income.

 

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Equity Method Investments

The Partnership’s consolidated financial statements include its 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”). The Partnership accounts for its investment in the joint ventures under the equity method of accounting. Under this method, the Partnership records its proportionate share of the joint ventures’ net income as equity income on its consolidated statements of operations. Investments in excess of the underlying net assets of equity method investees identifiable to property, plant and equipment or finite lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to equity investment on the Partnership’s consolidated balance sheet with an offsetting reduction to equity income on the Partnership’s consolidated statements of operations. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. This goodwill is not subject to amortization and is accounted for as a component of the investment. No goodwill was recorded on the acquisition of WTLPG. The Partnership had $86.2 million and $86.0 million equity method investment in WTLPG at March 31, 2013 and December 31, 2012, respectively, which was included with equity method investment in joint venture on its consolidated balance sheets. The Partnership recorded equity income in joint venture of $2.0 million and $0.9 million on its consolidated statements of operations for the three months ended March 31, 2013 and March 31, 2012, respectively, related to its interest in WTLPG.

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 by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, and net income (loss) attributable to the General Partner’s and the preferred unitholders’ interests. The General Partner’s interest in net income (loss) is calculated on a quarterly basis based upon its 2% general partner interest and incentive distributions to be distributed for the quarter (see Note 4), with a priority allocation of net income to the General Partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the General Partner’s and limited partners’ ownership interests.

The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

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 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless

 

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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. Therefore, the net income (loss) utilized in the calculation of net income (loss) per unit must be determined based upon the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income (loss) allocated to the General Partner and common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands):

 

     Three Months Ended
March 31,
 
     2013     2012  

Net income (loss)

   $ (27,492   $ 6,471   

Income attributable to non-controlling interests

     (1,369     (1,536
  

 

 

   

 

 

 

Net income (loss) attributable to common limited partners and the General Partner

     (28,861     4,935   
  

 

 

   

 

 

 

General Partner’s cash incentive distributions declared

     2,986        1,397   

General Partner’s ownership interest

     (641     71   
  

 

 

   

 

 

 

Net income attributable to the General Partner’s ownership interests

     2,345        1,468   
  

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

     (31,206     3,467   

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

     —          25   
  

 

 

   

 

 

 

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

   $ (31,206   $ 3,442   
  

 

 

   

 

 

 

 

(1) Net income attributable to common limited partners’ ownership interest is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three months ended March 31, 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 1,055,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, plus income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding plus the dilutive effect of outstanding participating securities and 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 14).

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

 

     Three Months Ended
March 31,
 
     2013      2012  

Weighted average number of common limited partner units – basic

     64,646         53,620   

Add effect of participating securities – phantom units(1)

     —           393   
  

 

 

    

 

 

 

Weighted average common limited partner units – diluted

     64,646         54,013   
  

 

 

    

 

 

 

 

(1) For the three months ended March 31, 2013 approximately 1,055,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such phantom units would have been anti-dilutive.

 

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Revenue Recognition

The Partnership’s revenue primarily consists of the sale of natural gas and NGLs along with the fees earned from its gathering, processing, treating and transportation operations. Under certain agreements, the Partnership purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced NGLs, if any, off delivery points on its systems. Under other agreements, the Partnership 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 the Partnership’s gathering, processing and transportation operations, it enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas and for transporting NGLs. Revenue is a function of the volume of natural gas that the Partnership gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. The Partnership 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.

POP Contracts. These contracts provide for the Partnership 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, the Partnership and the producer are directly dependent on the volume of the commodity and its value; the Partnership 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 the Partnership, 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 the Partnership’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. The Partnership must make up or “keep the producer whole” for this loss in BTU quantity. To offset the make-up obligation, the Partnership retains the NGLs, which are extracted, and sells them for its own account. Therefore, the Partnership bears the economic risk (the “processing margin risk”) that (1) the BTU quantity of residue gas available for redelivery to the producer may be less than received from the producer; and/or (2) the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount the Partnership paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts the Partnership 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 risk is uneconomic.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from the Partnership’s records and management estimates of the related gathering and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at March 31, 2013 and December 31, 2012 of $87.3 million and $100.8 million, respectively, which are included in accounts receivable within its consolidated balance sheets.

 

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Recently Adopted Accounting Standards

In February 2013, the FASB issued Accounting Standards Update (“ASU”) 2013-02, “Other Comprehensive Income (Topic 220) – Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which, among other changes, requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component and the respective line items of net income to which the amounts were reclassified. The update does not change the components of comprehensive income that must be presented. These requirements are effective for interim and annual reporting periods beginning after December 15, 2012. The Partnership began including the additional required disclosures upon the adoption of this ASU on January 1, 2013 (see “Comprehensive Income (Loss)”). The adoption had no material impact on the Partnership’s financial position or results of operations.

NOTE 3 – ACQUISITIONS

On December 20, 2012, the Partnership completed the acquisition of 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.5 million in cash, including preliminary purchase price adjustments, less cash received (the “Cardinal Acquisition”). The assets of these companies include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas. The acquisition includes a 60% interest in Centrahoma Processing, LLC (“Centrahoma”). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE).

The Partnership accounted for this transaction as a business combination. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values. As of March 31, 2013, the accounting for the business combination has not been completed. The estimates of fair value reflected as of March 31, 2013 are subject to change and changes could be material. Revisions to these estimates will be recorded retrospectively during the measurement period of one year from the acquisition date of December 20, 2012.

 

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The following table presents the preliminary values assigned as of March 31, 2013 and December 31, 2012 to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their estimated fair values at the date of the acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands):

 

     March 31, 2013     December 31, 2012  

Cash

   $ 3,246      $ 3,246   

Accounts receivable

     19,618        19,618   

Prepaid expenses and other

     1,377        1,377   

Property, plant and equipment

     295,855        295,855   

Intangible assets – contracts

     107,530        107,530   

Goodwill

     310,904        310,904   
  

 

 

   

 

 

 

Total assets acquired

     738,530        738,530   
  

 

 

   

 

 

 

Current portion of long-term debt

     (341     (341

Accounts payable and accrued liabilities

     (16,496     (16,496

Deferred tax liability, net

     (30,082     (30,082

Long-term debt, less current portion

     (604     (604
  

 

 

   

 

 

 

Total liabilities acquired

     (47,523     (47,523
  

 

 

   

 

 

 

Non-controlling interest

     (89,310     (89,310
  

 

 

   

 

 

 

Net assets acquired

     601,697        601,697   

Less cash received

     (3,246     (3,246
  

 

 

   

 

 

 

Net cash paid for acquisition

   $ 598,451      $ 598,451   
  

 

 

   

 

 

 

The fair value of MarkWest’s 40% non-controlling interest in Centrahoma was determined based upon the purchase price allocated to the 60% controlling interest the Partnership acquired.

NOTE 4 – EQUITY

Common Units

The Partnership has an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, the Partnership may offer and sell from time to time through Citigroup, as its sales agent, common units having an aggregate value of up to $150.0 million. Subject to the terms and conditions of the equity distribution agreement, Citigroup will not be required to sell any specific number or dollar amount of the common units, but will use its reasonable efforts, consistent with its normal trading and sales practices, to sell such units. Such sales will be at market prices prevailing at the time of the sale. There will be no specific date on which the offering will end; there will be no minimum purchase requirements; and there will be no arrangements to place the proceeds of the offering in an escrow, trust or similar account. Under the terms of the equity distribution agreement, the Partnership also may sell common units to Citigroup as principal for its own account at a price agreed upon at the time of the sale. The Partnership intends to use the net proceeds from any such offering for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. During the three months ended March 31, 2013, the Partnership issued 447,785 common units under the equity distribution program for net proceeds of $14.1 million, net of $0.3 million in commission paid to Citigroup. The Partnership also received a capital contribution from the General Partner of $0.3 million to maintain its 2.0% general partner interest in the Partnership. The net proceeds from the common unit offering were utilized for general partnership purposes.

Cash Distributions

The Partnership is required to distribute, within 45 days after the end of each quarter, all its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the General Partner. If common unit distributions in any quarter exceed specified target levels, the General

 

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Partner will receive between 15% and 50% of such distributions in excess of the specified target levels, including the General Partner’s 2% interest. The General Partner, which holds all the incentive distribution rights in the Partnership, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to the Partnership after the General Partner receives the initial $7.0 million per quarter of incentive distribution rights. Common unit and General Partner distributions declared by the Partnership for quarters ending from March 31, 2012 through December 31, 2012 were as follows:

 

          Cash      Total Cash      Total Cash  
          Distribution      Distribution      Distribution  
     Date Cash    Per Common      to Common      to the  
For Quarter    Distribution    Limited      Limited      General  

Ended

  

Paid

   Partner Unit      Partners      Partner  
                 (in thousands)      (in thousands)  

March 31, 2012

   May 15, 2012    $ 0.56       $ 30,030       $ 2,217   

June 30, 2012

   August 14, 2012      0.56         30,085         2,221   

September 30, 2012

   November 14, 2012      0.57         30,641         2,409   

December 31, 2012

   February 14, 2013      0.58         37,442         3,117   

On April 24, 2013, the Partnership declared a cash distribution of $0.59 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $49.3 million distribution, including $4.0 million to the General Partner for its general partner interest and incentive distribution rights, will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013.

NOTE 5 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment, including leased property and equipment meeting capital lease criteria (see Note 12) (in thousands):

 

                 Estimated
     March 31,     December 31,     Useful Lives
     2013     2012    

in Years

Pipelines, processing and compression facilities

   $ 2,412,743      $ 2,294,024      2 – 40

Rights of way

     180,884        178,234      20 – 40

Buildings

     8,225        8,224      40

Furniture and equipment

     10,904        10,305      3 – 7

Other

     14,774        14,761      3 – 10
  

 

 

   

 

 

   
     2,627,530        2,505,548     

Less – accumulated depreciation

     (327,563     (305,167  
  

 

 

   

 

 

   
   $ 2,299,967      $ 2,200,381     
  

 

 

   

 

 

   

The Partnership recorded depreciation expense on property, plant and equipment, including capital lease arrangements (see Note 12), of $22.3 million and $15.0 million for the three months ended March 31, 2013 and 2012, respectively, on its consolidated statements of operations.

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds was 6.1% and 6.7% for the three months ended March 31, 2013 and 2012, respectively. The amount of interest capitalized was $2.5 million and $2.2 million for the three months ended March 31, 2013 and 2012, respectively.

 

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NOTE 6 –GOODWILL AND INTANGIBLE ASSETS

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership reflected goodwill on its consolidated balance sheets of $319.3 million at both March 31, 2013 and December 31, 2012. The goodwill is related to acquisitions completed during the year ended December 31, 2012, including the Cardinal Acquisition. The goodwill related to the Cardinal Acquisition is a result of the strategic industry position and potential future synergies.

The Partnership has recorded intangible assets with finite lives in connection with certain consummated acquisitions. The following table reflects the components of intangible assets being amortized at March 31, 2013 and December 31, 2012 (in thousands):

 

           Estimated
     March 31,     December 31,     Useful Lives
     2013     2012     In Years

Gross carrying amount:

      

Customer contracts

   $ 111,500      $ 119,933      10-14

Customer relationships

     205,313        205,313      7–10
  

 

 

   

 

 

   
     316,813        325,246     
  

 

 

   

 

 

   

Accumulated amortization:

      

Customer contracts

     (3,112     (746  

Customer relationships

     (130,915     (125,140  
  

 

 

   

 

 

   
     (134,027     (125,886  
  

 

 

   

 

 

   

Net carrying amount:

      

Customer contracts

     108,388        119,187     

Customer relationships

     74,398        80,173     
  

 

 

   

 

 

   

Net carrying amount

   $ 182,786      $ 199,360     
  

 

 

   

 

 

   

The weighted-average amortization period for customer contracts and customer relationships is 9.8 years and 9.1 years, respectively. The Partnership recorded amortization expense on intangible assets of $8.1 million and $5.8 million for the three months ended March 31, 2013 and 2012, respectively, on its consolidated statements of operations. Amortization expense related to intangible assets is estimated to be as follows for each of the next five calendar years: remainder of 2013 - $25.7 million; 2014 – $30.7 million; 2015 through 2016 - $25.7 million per year; 2017 - $19.6 million.

The Partnership completed an acquisition of a gas gathering system and related assets in June 2012. The Partnership accounted for the acquisition as a business combination and initially recognized $10.6 million related to customer contracts with an estimated useful life of 14 years. The initial recording of the transaction was based upon preliminary valuation assessments. The Partnership completed its assessments of the fair value of assets acquired and liabilities assumed during the three months ended March 31, 2013 and adjusted the final purchase price allocation, including an $8.4 million reduction of the fair value of intangible assets with finite lives.

The valuation assessment for the Cardinal Acquisition has not been completed as of March 31, 2013. The estimates of fair value of goodwill and intangible assets with finite lives reflected as of March 31, 2013 are subject to change and the change may be material. Revision to these estimates will be recorded retrospectively (see Note 3).

 

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NOTE 7 – OTHER ASSETS

The following is a summary of other assets (in thousands):

 

     March 31,      December 31,  
     2013      2012  

Deferred finance costs, net of accumulated amortization of $16,612 and $23,536 at March 31, 2013 and December 31, 2012, respectively

   $ 36,686       $ 30,496   

Security deposits

     1,972         2,097   
  

 

 

    

 

 

 
   $ 38,658       $ 32,593   
  

 

 

    

 

 

 

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 12). During the three months ended March 31, 2013 and 2012, the Partnership incurred $13.0 million and $0.1 million deferred finance costs, respectively, related to various financing activities (see Note 12). During the three months ended March 31, 2013, the Partnership redeemed all of its outstanding $365.8 million 8.75% unsecured senior notes due June 15, 2018 (“8.75% Senior Notes”) (see Note 12). The Partnership recorded $5.3 million of accelerated amortization of deferred financing costs associated with the retirement of debt during the three months ended March 31, 2013, included in loss on early extinguishment of debt on the Partnership’s consolidated statement of operations, related to the retirement of the 8.75% Senior Notes. There was no accelerated amortization of deferred financing costs during the three months ended March 31, 2012. Amortization expense of deferred finance costs, excluding accelerated amortization expense was $1.5 million and $1.2 million for the three months ended March 31, 2013 and 2012, respectively, which is recorded within interest expense on the Partnership’s consolidated statements of operations. Amortization expense related to remaining deferred finance costs is estimated to be as follows for each of the next five calendar years: remainder of 2013 - $4.5 million; 2014 to 2016 - $6.0 million per year; 2017 - $3.9 million.

NOTE 8 – INCOME TAXES

As part of the Cardinal Acquisition (see Note 3), the Partnership acquired APL Arkoma, Inc., a taxable subsidiary. The components of the federal and state income tax benefit of the Partnership’s taxable subsidiary at March 31, 2013 are summarized as follows (in thousands):

 

     Three Months
Ended
 
     March 31, 2013  

Deferred benefit :

  

Federal

   $ (8

State

     (1
  

 

 

 

Total income tax benefit

   $ (9
  

 

 

 

 

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The components of net deferred tax liabilities as of March 31, 2013 and December 31, 2012 consist of the following (in thousands):

 

     March 31,
2013
    December 31,
2012
 

Deferred tax assets:

    

Net operating loss tax carryforwards and alternative minimum tax credits

   $ 10,864      $ 10,277   

Deferred tax liabilities:

    

Excess of asset carrying value over tax basis

     (41,113     (40,535
  

 

 

   

 

 

 

Net deferred tax liabilities

   $ (30,249   $ (30,258
  

 

 

   

 

 

 

As of March 31, 2013, the Partnership had net operating loss carry forwards for federal income tax purposes of approximately $27.9 million, which expire at various dates from 2029 to 2032. Management of the General Partner believes it more likely than not that the deferred tax asset will be fully utilized.

NOTE 9 — DERIVATIVE INSTRUMENTS

The Partnership uses derivative instruments in connection with its commodity price risk management activities. The Partnership uses financial swap and put option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under its swap agreements, the Partnership receives a fixed price and remits a floating price based on certain indices for the relevant contract period. The swap agreement sets a fixed price for the product being hedged. 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 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. A costless collar is a combination of a purchased put option and a sold call option, in which the premiums net to zero. A costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

The Partnership no longer applies hedge accounting for derivatives. Changes in fair value of derivatives are recognized immediately within derivative gain (loss), net in its consolidated statements of operations. The change in fair value of commodity-based derivative instruments, which was previously recognized in accumulated other comprehensive loss within equity on the Partnership’s consolidated balance sheets, was reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings.

The Partnership 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 setoff at the time of settlement of the derivatives. Due to the right of setoff, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options. Changes in the fair value of the options are recognized within derivative gain (loss), net as unrealized gain (loss) on the Partnership’s consolidated statements of operations. Premiums are reclassified to realized gain (loss) within derivative gain (loss), net at the time the option expires or is exercised. The Partnership reflected net derivative assets on its consolidated balance sheets of $18.2 million and $31.0 million at March 31, 2013 and December 31, 2012, respectively.

 

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The following tables summarize the Partnership’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands):

Offsetting of Derivative Assets

 

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

As of March 31, 2013:

       

Current portion of derivative assets

   $ 19,872       $ (2,481   $ 17,391   

Long-term portion of derivative assets

     4,570         (2,192     2,378   

Long-term portion of derivative liabilities

     3,248         (3,248     —     
  

 

 

    

 

 

   

 

 

 

Total derivative assets, net

   $ 27,690       $ (7,921   $ 19,769   
  

 

 

    

 

 

   

 

 

 

As of December 31, 2012:

       

Current portion of derivative assets

   $ 23,534       $ (457   $ 23,077   

Long-term portion of derivative assets

     9,637         (1,695     7,942   
  

 

 

    

 

 

   

 

 

 

Total derivative assets, net

   $ 33,171       $ (2,152   $ 31,019   
  

 

 

    

 

 

   

 

 

 

Offsetting of Derivative Liabilities

 

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

As of March 31, 2013:

       

Current portion of derivative assets

   $ (2,481   $ 2,481       $ —     

Long-term portion of derivative assets

     (2,192     2,192         —     

Current portion of derivative liabilities

     (619     —           (619

Long-term portion of derivative liabilities

     (4,173     3,248         (925
  

 

 

   

 

 

    

 

 

 

Total derivative liabilities, net

   $ (9,465   $ 7,921       $ (1,544
  

 

 

   

 

 

    

 

 

 

As of December 31, 2012:

       

Current portion of derivative liabilities

   $ (457   $ 457       $ —     

Long-term portion of derivative liabilities

     (1,695     1,695         —     
  

 

 

   

 

 

    

 

 

 

Total derivative liabilities, net

   $ (2,152   $ 2,152       $ —     
  

 

 

   

 

 

    

 

 

 

 

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The following table summarizes the Partnership’s commodity derivatives as of March 31, 2013, (dollars and volumes in thousands):

 

Production Period

    

Commodity

     Volumes(1)        Average
Fixed Price
($/Volume)
       Fair  Value(2)
Asset/
(Liability)
 

Fixed price swaps

                   

2013

     Natural gas        3,130         $ 3.61         $ (1,692

2014

     Natural gas        12,000           3.96           (3,065

2015

     Natural gas        12,100           4.21           (1,091

2016

     Natural gas        1,200           4.40           23   

2013

     NGLs        41,454           1.27           11,727   

2014

     NGLs        46,746           1.22           1,177   

2015

     NGLs        23,688           1.11           (1,111

2013

     Crude oil        252           97.05           32   

2014

     Crude oil        303           92.38           (222
                   

 

 

 

Total fixed price swaps

                      5,778   
                   

 

 

 

Options

                   

Purchased put options

                   

2013

     Natural gas        600           4.13           270   

2013

     NGLs        32,508           1.88           4,712   

2013

     Crude oil        216           100.10           1,287   

2014

     Crude oil        389           95.24           3,517   

2015

     Crude oil        270           89.18           2,661   
                   

 

 

 

Total options

                      12,447   
                   

 

 

 

Total derivatives

                    $ 18,225   
                   

 

 

 

 

(1) NGL volumes are stated in gallons. Crude oil volumes are stated in barrels. Natural gas volumes are stated in MMBTUs.
(2) See Note 10 for discussion on fair value methodology.

The following tables summarize the gross effect of all derivative instruments on the Partnership’s consolidated statements of operations for the periods indicated (in thousands):

 

     For the Three Months ended
March 31,
 
     2013     2012  

Derivatives previously designated as cash flow hedges

    

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

   $ —        $ (1,146
  

 

 

   

 

 

 

Derivatives not designated as hedges

    

Loss recognized in derivative loss, net

    

Commodity contract - realized(1)

   $ 1,636      $ (763

Commodity contract - unrealized(2)

     (13,719     (11,272
  

 

 

   

 

 

 

Derivative loss, net

   $ (12,083   $ (12,035
  

 

 

   

 

 

 

 

(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.

 

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NOTE 10 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:

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.

The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 9). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership has a financial risk management committee (the “Financial Risk Management Committee”), which sets the policies, procedures and valuation methods utilized by the Partnership to value its derivative contracts. The Financial Risk Management Committee members include, among others, the Chief Executive Officer, the Chief Financial Officer and the Vice Chairman of the managing board of the General Partner. The Financial Risk Management Committee receives daily reports and meets on a weekly basis to review the risk management portfolio and changes in the fair value in order to determine appropriate actions.

Derivative Instruments

At March 31, 2013, the valuations for all the Partnership’s derivative contracts are defined as Level 2 assets and liabilities within the same class of nature and risk, with the exception of the Partnership’s NGL fixed price swaps and NGL options, which are defined as Level 3 assets and liabilities within the same class of nature and risk.

The Partnership’s Level 2 commodity derivatives include natural gas and crude oil swaps and options, which are calculated based upon observable market data related to the change in price of the underlying commodity. These swaps and options are calculated by utilizing the New York Mercantile Exchange (“NYMEX”) quoted prices for futures and option 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 the Partnership’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 the Partnership utilizes the valuations provided by the financial institutions that provide the NGL options for trade. The Partnership tests these valuations for reasonableness through the use of an internal valuation model.

Valuations for the Partnership’s NGL fixed price swaps are based on forward price curves provided by a third party, which the Partnership considers to be Level 3 inputs. The prices 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

 

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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.

The following table represents the Partnership’s derivative assets and liabilities recorded at fair value as of March 31, 2013 and December 31, 2012 (in thousands):

 

     Level 1      Level 2     Level 3     Total  

March 31, 2013

       

Assets

       

Commodity swaps

   $ —         $ 1,141      $ 14,102      $ 15,243   

Commodity options

     —           7,735        4,712        12,447   
  

 

 

    

 

 

   

 

 

   

 

 

 

Total assets

     —           8,876        18,814        27,690   
  

 

 

    

 

 

   

 

 

   

 

 

 

Liabilities

       

Commodity swaps

     —           (7,156     (2,309     (9,465
  

 

 

    

 

 

   

 

 

   

 

 

 

Total liabilities

     —           (7,156     (2,309     (9,465
  

 

 

    

 

 

   

 

 

   

 

 

 

Total derivatives

   $ —         $ 1,720      $ 16,505      $ 18,225   
  

 

 

    

 

 

   

 

 

   

 

 

 

December 31, 2012

       

Assets

       

Commodity swaps

   $ —         $ 2,007      $ 17,573      $ 19,580   

Commodity options

     —           7,322        6,269        13,591   
  

 

 

    

 

 

   

 

 

   

 

 

 

Total assets

     —           9,329        23,842        33,171   
  

 

 

    

 

 

   

 

 

   

 

 

 

Liabilities

       

Commodity swaps

     —           (1,393     (759     (2,152
  

 

 

    

 

 

   

 

 

   

 

 

 

Total liabilities

     —           (1,393     (759     (2,152
  

 

 

    

 

 

   

 

 

   

 

 

 

Total derivatives

   $ —         $ 7,936      $ 23,083      $ 31,019   
  

 

 

    

 

 

   

 

 

   

 

 

 

The Partnership’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of the Partnership’s Level 3 derivative instruments for the three months ended March 31, 2013 (in thousands):

 

     NGL Fixed Price Swaps     NGL Put Options     Total  
     Gallons     Amount     Gallons     Amount     Amount  

Balance – December 31, 2012

     87,066      $ 16,814        38,556      $ 6,269      $ 23,083   

New contracts(1)

     39,312        —          1,260        88        88   

Cash settlements from unrealized gain (loss)(2)(3)

     (14,490     (3,888     (7,308     2,044        (1,844

Net change in unrealized gain (loss)(2)

     —          (1,133     —          (1,290     (2,423

Deferred option premium recognition(3)

     —          —          —          (2,399     (2,399
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance – March 31, 2013

     111,888      $ 11,793        32,508      $ 4,712      $ 16,505   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 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.
(2) Included within derivative loss, net on the Partnership’s consolidated statements of operations.
(3) Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration.

 

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The following table provides a summary of the unobservable inputs used in the fair value measurement of the Partnership’s NGL fixed price swaps at March 31, 2013 and December 31, 2012 (in thousands):

 

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

As of March 31, 2013

         

Propane swaps

     92,736       $ 9,906      $ (319   $ 9,587   

Isobutane swaps

     630         48        78        126   

Normal butane swaps

     5,040         233        134        367   

Natural gasoline swaps

     13,482         3,978        (2,265     1,713   
  

 

 

    

 

 

   

 

 

   

 

 

 

Total NGL swaps – March 31, 2013

     111,888       $ 14,165      $ (2,372   $ 11,793   
  

 

 

    

 

 

   

 

 

   

 

 

 

As of December 31, 2012

         

Propane swaps

     69,678       $ 16,302      $ (552   $ 15,750   

Isobutane swaps

     1,134         (219     187        (32

Normal butane swaps

     6,174         (909     242        (667

Natural gasoline swaps

     10,080         3,247        (1,484     1,763   
  

 

 

    

 

 

   

 

 

   

 

 

 

Total NGL swaps – December 31, 2012

     87,066       $ 18,421      $ (1,607   $ 16,814   
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap.
(2) Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three year historical period.

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

 

    

Level 3 NGL

Swap Fair

    Adjustment based upon
Regression Coefficient
 
     Value
Adjustments
    Lower
95%
     Upper
95%
     Average  
As of March 31, 2013:           

Propane

   $ (319     0.8969         0.9069         0.9019   

Isobutane

     78        1.1274         1.1366         1.1320   

Normal butane

     134        1.0384         1.0430         1.0407   

Natural gasoline

     (2,265     0.9063         0.9251         0.9157   
  

 

 

         

Total Level 3 adjustments – March 31, 2013

   $ (2,372        
  

 

 

         
As of December 31, 2012:           

Propane

   $ (552     0.9019         0.9122         0.9071   

Isobutane

     187        1.1285         1.1376         1.1331   

Normal butane

     242        1.0370         1.0416         1.0393   

Natural gasoline

     (1,484     0.8988         0.9169         0.9078   
  

 

 

         

Total Level 3 adjustments – December 31, 2012

   $ (1,607        
  

 

 

         

The Partnership had $7.8 million of NGL linefill at both March 31, 2013 and December 31, 2012, which was included within prepaid expenses and other on its consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price. The Partnership’s NGL linefill is defined as a Level 3 asset and is valued using the same forward price curve utilized to

 

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value the Partnership’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was a reduction of $0.4 million and $0.4 million as of March 31, 2013 and December 31, 2012, respectively.

The following table provides a summary of changes in fair value of the Partnership’s NGL linefill for the three months ended March 31, 2013 (in thousands):

 

     NGL Linefill  
     Gallons      Amount  

Balance – December 31, 2012

     9,148       $ 7,783   

Net change in NGL linefill valuation(1)

     —           (32
  

 

 

    

 

 

 

Balance – March 31, 2013

     9,148       $ 7,751   
  

 

 

    

 

 

 

 

(1) Included within natural gas and liquid sales on the Partnership’s consolidated statements of operations.

Contingent Consideration

In February 2012, the Partnership acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. The Partnership originally agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period (“Trigger Payments”). Sufficient volumes were achieved in December 2012 and the Partnership paid the first Trigger Payment of $6.0 million in January 2013. As of March 31, 2013, the fair value of the remaining Trigger Payment resulted in a $6.0 million long term liability, which was recorded within other long term liabilities on the Partnership’s consolidated balance sheets. The range of the undiscounted amount the Partnership could pay related to the remaining Trigger Payment is between $0.0 and $6.0 million.

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts the Partnership could realize upon the sale or refinancing of such financial instruments.

The Partnership’s current assets and liabilities on its consolidated balance sheets, other than the derivatives, NGL linefill and contingent consideration discussed above, are considered to be financial instruments for which the estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1 values. The carrying value of outstanding borrowings under the revolving credit facility, which bear interest at a variable interest rate, approximates their estimated fair value and thus is categorized as a Level 1 value. The estimated fair value of the Partnership’s Senior Notes (see Note 12) is based upon the market approach and calculated using the yield of the Senior Notes as provided by financial institutions and thus is categorized as a Level 3 value. The estimated fair values of the Partnership’s total debt at March 31, 2013 and December 31, 2012, which consists principally of borrowings under the revolving credit facility and the Senior Notes, were $1,329.0 million and $1,216.4 million, respectively, compared with the carrying amounts of $1,318.9 million and $1,179.9 million, respectively.

 

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Acquisitions

On December 20, 2012, the Partnership completed the Cardinal Acquisition (see Note 3). 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. These inputs require significant judgments and estimates at the time of the valuation. As of March 31, 2013, the accounting for the Cardinal Acquisition has not been completed. The estimates of fair value as of the acquisition date, which are reflected as of March 31, 2013, are subject to change and the changes made could be material. Revisions to these estimates will be recorded retrospectively.

NOTE 11 – ACCRUED LIABILITIES

The following is a summary of accrued liabilities (in thousands):

 

     March 31,      December 31,  
     2013      2012  

Accrued capital expenditures

   $ 9,362       $ 8,336   

Cardinal Acquisition payable (offset by funds in escrow)

     25,001         25,000   

Acquisition-based short-term contingent consideration

     —           6,000   

Accrued ad valorem taxes

     6,782         3,950   

Other

     5,862         14,466   
  

 

 

    

 

 

 
   $ 47,007       $ 57,752   
  

 

 

    

 

 

 

NOTE 12 — DEBT

Total debt consists of the following (in thousands):

 

     March 31,     December 31,  
     2013     2012  

Revolving credit facility

   $ 154,500      $ 293,000   

8.750% Senior notes – due 2018

     —          370,184   

6.625% Senior notes – due 2020

     505,063        505,231   

5.875% Senior notes – due 2023

     650,000        —     

Capital lease obligations

     9,349        11,503   
  

 

 

   

 

 

 

Total debt

     1,318,912        1,179,918   

Less current maturities

     (8,861     (10,835
  

 

 

   

 

 

 

Total long term debt

   $ 1,310,051      $ 1,169,083   
  

 

 

   

 

 

 

Cash payments for interest related to debt, net of capitalized interest, were a net expense of $22.1 million for the three months ended March 31, 2013 and a net credit of $0.6 million for the three months ended March 31, 2012.

Revolving Credit Facility

At March 31, 2013, the Partnership had a $600.0 million senior secured revolving credit facility with a syndicate of banks that matures in May 2017. Borrowings under the revolving credit facility bear interest, at the Partnership’s option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (2) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for borrowings on the revolving credit facility, at March 31, 2013, was 2.5%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at March 31, 2013. These outstanding letters of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheets. At March 31, 2013, the Partnership had $445.4 million of remaining committed capacity under its revolving credit facility.

 

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Borrowings under the revolving credit facility are secured by (i) a lien on and security interest in all the Partnership’s property and that of its subsidiaries, except for the assets owned by Atlas Pipeline Mid-Continent WestOk, LLC (“WestOK LLC”) and Atlas Pipeline Mid-Continent WestTex, LLC (“WestTX LLC”), entities in which the Partnership has 95% interests, and Centrahoma, in which the Partnership has a 60% interest; and their respective subsidiaries; and (ii) by the guaranty of each of the Partnership’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including requirements that the Partnership maintain certain financial thresholds and restrictions on the Partnership’s ability to (1) incur additional indebtedness, (2) make certain acquisitions, loans or investments, (3) make distribution payments to its unitholders if an event of default exists, or (4) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. The Partnership is unable to borrow under its revolving 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 that 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 the Partnership in excess of a specified amount, and a change of control of the Partnership’s General Partner. As of March 31, 2013, the Partnership was in compliance with all covenants under the credit facility.

Senior Notes

At March 31, 2013, the Partnership had $500.0 million principal outstanding of 6.625% unsecured senior notes due October 1, 2020 (“6.625% Senior Notes) and $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% Senior Notes,” and with the 6.625% Senior Notes, the “Senior Notes”).

The 6.625% Senior Notes are presented combined with a net $5.1 million unamortized premium as of March 31, 2013. Interest on the 6.625% Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% Senior Notes are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

In connection with the issuance of the 6.625% Senior Notes, the Partnership entered into registration rights agreements, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by September 23, 2013 in the case of the 6.625% Senior Notes issued in September 2012, or by December 15, 2013, in the case of the 6.625% Senior Notes issued in December 2012. If the Partnership does not meet the aforementioned deadline, the 6.625% Senior Notes issued on September 28, 2012 and December 20, 2012 will be subject to additional interest, up to 1% per annum, until such time that the Partnership causes the exchange offer to be consummated. On April 12, 2013, the Partnership filed an amendment to its registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on April 12, 2013.

On February 11, 2013, the Partnership issued $650.0 million of the 5.875% Senior Notes in a private placement transaction. The 5.875% Senior Notes were issued at par. The Partnership received net proceeds of $637.1 million after underwriting commissions and other transactions costs and utilized the proceeds to redeem the 8.75% unsecured senior notes due June 15, 2018 (“8.75% Senior Notes”) and repay a portion of the outstanding indebtedness under the revolving credit agreement. Interest on the 5.875% Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

 

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In connection with the issuance of the 5.875% Senior Notes, the Partnership entered into registration rights agreements, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by February 6, 2014. If the Partnership does not meet the aforementioned deadline, the 5.875% Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the Partnership causes the exchange offer to be consummated.

On January 28, 2013, the Partnership commenced a cash tender offer for any and all of its outstanding $365.8 million 8.75% Senior Notes, excluding unamortized premium, and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% Senior Notes (“8.75% Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, the Partnership accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million make-whole premium, $3.7 million accrued interest and $8.0 million consent payment. The Partnership entered into a supplemental indenture amending and supplementing the 8.75% Senior Notes Indenture. The Partnership also issued a notice to redeem all the 8.75% Senior Notes not purchased in connection with the tender offer.

On March 12, 2013, the Partnership paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% Senior Notes plus a $6.3 million make-whole premium and $2.0 million in accrued interest. The Partnership funded the redemption with a portion of the net proceeds from the issuance of the 5.875% Senior Notes. For the three months ended March 31, 2013, the Partnership recorded a loss of $26.6 million within loss on early extinguishment of debt on the Partnership’s consolidated statements of operations, related to the redemption of the 8.75% Senior Notes. The loss includes $17.5 million premiums paid; $8.0 million consent payment; $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium.

The Senior Notes are subject to repurchase by the Partnership 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 the Partnership does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Partnership’s secured debt, including the Partnership’s obligations under its revolving credit facility.

Indentures governing the Senior Notes contain covenants, including limitations of the Partnership’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all its assets. The Partnership is in compliance with these covenants as of March 31, 2013.

Capital Leases

The following is a summary of the leased property under capital leases as of March 31, 2013 and December 31, 2012, which are included within property, plant and equipment (see Note 5) (in thousands):

 

     March 31,     December 31,  
     2013     2012  

Pipelines, processing and compression facilities

   $ 15,457      $ 15,457   

Less – accumulated depreciation

     (1,277     (1,066
  

 

 

   

 

 

 
   $ 14,180      $ 14,391   
  

 

 

   

 

 

 

 

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Depreciation expense for leased properties was $211 thousand and $167 thousand for the three months ended March 31, 2013 and 2012, respectively, which is included within depreciation and amortization expense on the Partnership’s consolidated statements of operations (see Note 5).

NOTE 13 — COMMITMENTS AND CONTINGENCIES

The Partnership 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 the Partnership’s operations. During the three months ended March 31, 2013 and 2012, the Partnership paid $3.0 million and $2.5 million, respectively, for transportation fees related to these contracts. The future fixed and determinable portion of the obligations as of March 31, 2013 was as follows: remainder of 2013 - $7.0 million; 2014 - $9.5 million; and 2015 to 2017 - $3.5 million per year.

The Partnership had committed approximately $50.3 million for the purchase of property, plant and equipment at March 31, 2013.

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership believes that the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.

NOTE 14 — BENEFIT PLANS

Generally, all share-based payments to employees, which are not cash settled, including grants of unit options and phantom units, are recognized within equity in the financial statements based on their fair values on the date of the 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.

A phantom unit entitles a grantee to receive a common limited partner unit upon vesting of the phantom unit. In tandem with phantom unit grants, participants may be granted a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to and at the same time as the cash distributions the Partnership makes on a common unit during the period the phantom unit is outstanding. The compensation committee appointed by the General Partner’s managing board (the “Compensation Committee”) determines the vesting period for phantom units.

A unit option entitles a grantee to purchase a common limited partner unit 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 common unit on the date of grant of the option. The Compensation Committee determines how the exercise price may be paid by the grantee as well as the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. There were no unit options outstanding as of March 31, 2013.

Long-Term Incentive Plans

The Partnership has a 2004 Long-Term Incentive Plan (“2004 LTIP”) and a 2010 Long-Term Incentive Plan (“2010 LTIP” and collectively with the 2004 LTIP, the “LTIPs”) in which officers, employees, non-employee managing board members of the General Partner, employees of the General Partner’s affiliates and consultants are eligible to participate. The LTIPs are administered by the

 

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Compensation Committee. Under the LTIPs, the Compensation Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At March 31, 2013, the Partnership had 1,057,083 phantom units outstanding under the Partnership’s LTIPs, with 1,517,513 phantom units and unit options available for grant. The Partnership generally issues new common units for phantom units and unit options, which have vested and have been exercised.

Partnership Phantom Units. Through March 31, 2013, phantom units granted to employees under the LTIPs generally had vesting periods of four years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of the board automatically vest upon a change of control, as defined in the LTIPs. At March 31, 2013, there were 292,809 units outstanding under the LTIPs that will vest within the following twelve months.

All phantom units outstanding under the LTIPs at March 31, 2013 include DERs granted to the participants by the Compensation Committee. The amounts paid with respect to LTIP DERs were $0.6 million and $0.2 million, during the three month ended March 31, 2013 and 2012, respectively. These amounts were recorded as reductions of equity on the Partnership’s consolidated balance sheets.

The following table sets forth the Partnership’s LTIPs phantom unit activity for the periods indicated:

 

     Three Months Ended March 31,  
     2013      2012  
     Number
of Units
    Fair
Value(1)
     Number
of Units
    Fair
Value(1)
 

Outstanding, beginning of period

     1,053,242      $ 33.21         394,489      $ 21.63   

Granted

     6,804        33.06         4,132        36.29   

Matured and issued(2)

     (2,963     28.94         (8,054     39.78   
  

 

 

   

 

 

    

 

 

   

 

 

 

Outstanding, end of period(3)(4)

     1,057,083      $ 33.22         390,567      $ 21.41   
  

 

 

   

 

 

    

 

 

   

 

 

 

Matured and not issued(5)

     —        $ —           4,125      $ 44.51   
  

 

 

   

 

 

    

 

 

   

 

 

 

Non-cash compensation expense recognized (in thousands)

     $ 4,384         $ 978   
    

 

 

      

 

 

 

 

(1) Fair value based upon weighted average grant date price.
(2) The intrinsic values for phantom unit awards exercised during the three months ended March 31, 2013 and 2012 were $0.1 million and $0.3 million, respectively.
(3) The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2013 and 2012 was $36.6 million and $13.8 million, respectively.
(4) There were 21,767 and 16,692 outstanding phantom unit awards at March 31, 2013 and 2012, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards.
(5) The aggregate intrinsic value for phantom unit awards vested but not issued at March 31, 2012 was $152 thousand.

At March 31, 2013, the Partnership had approximately $19.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.2 years.

NOTE 15 — RELATED PARTY TRANSACTIONS

The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by the General Partner and employees of ATLS. The General Partner does not receive a management fee in connection with its management of the Partnership apart from its interest as general partner and its right to receive incentive distributions. The Partnership reimburses the General Partner and its affiliates for compensation and benefits related to its employees who perform services for the Partnership based upon an estimate of the time spent by such persons on activities for the Partnership. Other indirect costs, such as rent for offices, are allocated to the Partnership by ATLS based on the number of its employees who devote their time to activities on the Partnership’s behalf.

 

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The partnership agreement provides that the General Partner will determine the costs and expenses allocable to the Partnership in any reasonable manner determined by the General Partner at its sole discretion. The Partnership reimbursed the General Partner and its affiliates $1.3 million and $0.9 million for the three months ended March 31, 2013 and 2012, respectively, for compensation and benefits related to its employees. There were no reimbursements for direct expenses incurred by the General Partner and its affiliates for the three months ended March 31, 2013 and 2012. The General Partner believes the method utilized in allocating costs to the Partnership is reasonable.

The Partnership compresses and gathers gas for Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP”) on its gathering systems located in Tennessee. ARP’s general partner is wholly-owned by ATLS, and two members of the General Partner’s managing board are members of ARP’s board of directors. The Partnership entered into an agreement to provide these services, which extends for the life of ARP’s leases, in February 2008. The Partnership charged ARP approximately $0.1 million, and $0.1 million in compression and gathering fees for the three months ended March 31, 2013 and 2012, respectively.

NOTE 16 — SEGMENT INFORMATION

The Partnership has two reportable segments: Gathering and Processing; and Transportation, Treating and Other (“Transportation and Treating”). These reportable segments reflect the way the Partnership manages its operations.

The Gathering and Processing segment consists of (1) the Arkoma, WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko, Arkoma and Permian Basins; and (2) the natural gas gathering assets located in the Barnett Shale play in Texas and the Appalachian Basin in Tennessee. Gathering and Processing revenues are primarily derived from the sale of residue gas and NGLs and the gathering, processing and treating of natural gas.

The Transportation and Treating segment consists of (1) contract gas treating operations located in various shale plays including the Avalon, Eagle Ford, Granite Wash, Haynesville, Fayetteville and Woodford; and (2) the Partnership’s 20% interest in the equity income generated by West Texas LPG Pipeline Limited Partnership, which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. Contract gas treating revenues are primarily derived from monthly lease fees for use of treating facilities. Pipeline revenues are primarily derived from transportation fees.

 

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The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):

 

     Gathering
and
Processing
    Transportation
and Treating
     Corporate
and Other
    Consolidated  

Three Months Ended March 31, 2013:

         

Revenue:

         

Revenues – third party(1)

   $ 418,607      $ 1,433       $ (12,199   $ 407,841   

Revenues – affiliates

     71        —           —          71   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total revenues

     418,678        1,433         (12,199     407,912   
  

 

 

   

 

 

    

 

 

   

 

 

 

Costs and Expenses:

         

Operating costs and expenses

     347,055        344         —          347,399   

General and administrative(1) `

     —          —           13,798        13,798   

Other costs

     —          —           530        530   

Depreciation and amortization

     29,971        268         219        30,458   

Interest expense(1)

     —          —           18,686        18,686   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     377,026        612         33,233        410,871   
  

 

 

   

 

 

    

 

 

   

 

 

 

Equity income in joint venture

     —          2,040         —          2,040   

Loss on early extinguishment of debt

     —          —           (26,582     (26,582

Income tax expense (benefit)

     (9     —           —          (9
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income (loss)

   $ 41,661      $ 2,861       $ (72,014   $ (27,492
  

 

 

   

 

 

    

 

 

   

 

 

 

Three Months Ended March 31, 2012:

         

Revenue:

         

Revenues – third party(1)

   $ 305,388      $ —         $ (13,181   $ 292,207   

Revenues – affiliates

     79        —           —          79   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total revenues

     305,467        —           (13,181     292,286   
  

 

 

   

 

 

    

 

 

   

 

 

 

Costs and expenses:

         

Operating costs and expenses

     247,167        83         —          247,250   

General and administrative(1)

     —          —           9,945        9,945   

Other costs

     (34     —           —          (34

Depreciation and amortization

     20,842        —           —          20,842   

Interest expense(1)

     —          —           8,708        8,708   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     267,975        83         18,653        286,711   
  

 

 

   

 

 

    

 

 

   

 

 

 

Equity income in joint venture

     —          896         —          896   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income (loss)

   $ 37,492      $ 813       $ (31,834   $ 6,471   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

(1) The Partnership notes derivative contracts are carried at the corporate level and interest and general and administrative expenses have not been allocated to its reportable segments as it would be unfeasible to reasonably do so for the periods presented.

 

     Three Months Ended
March 31,
 
      2013      2012  
Capital Expenditures:      

Gathering and processing

   $ 108,393       $ 81,167   

Transportation and treating

     123         —     
  

 

 

    

 

 

 
   $ 108,516       $ 81,167   
  

 

 

    

 

 

 

 

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Balance Sheet

   March 31,
2013
     December 31,
2012
 

Equity method investment in joint venture:

     

Transportation and Treating

   $ 86,242       $ 86,002   

Goodwill:

     

Gathering and Processing

     292,448         292,448   

Transportation and Treating

     26,837         26,837   
  

 

 

    

 

 

 
   $ 319,285       $ 319,285   
  

 

 

    

 

 

 

Total assets:

     

Gathering and Processing

   $ 2,926,959       $ 2,831,639   

Transportation and Treating

     139,809         141,356   

Corporate and other

     87,662         92,643   
  

 

 

    

 

 

 
   $ 3,154,430       $ 3,065,638   
  

 

 

    

 

 

 

The following table summarizes the Partnership’s natural gas and liquids sales by product or service for the periods indicated (in thousands):

 

     Three Months Ended  
     March 31,  
     2013     2012  

Natural gas and liquids sales:

    

Natural gas

   $ 141,484      $ 78,705   

NGLs

     217,831        188,694   

Condensate

     24,565        22,098   

Other

     (32     (272
  

 

 

   

 

 

 

Total

   $ 383,848      $ 289,225   
  

 

 

   

 

 

 

NOTE 17 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Partnership’s Senior Notes and revolving credit facility are guaranteed by its wholly-owned subsidiaries. The guarantees are full, unconditional, joint and several. The Partnership’s consolidated financial statements as of March 31, 2013 and December 31, 2012 and for the three months ended March 31, 2013 and 2012 include the financial statements of WestOK LLC, WestTX LLC, and Centrahoma. Under the terms of the Senior Notes and the revolving credit facility, WestOK LLC, WestTX LLC and Centrahoma are non-guarantor subsidiaries as they are not wholly-owned by the Partnership. The following supplemental condensed consolidating financial information reflects the Partnership’s stand-alone accounts, the combined accounts of the guarantor subsidiaries, the combined accounts of the non-guarantor subsidiaries, the consolidating adjustments and eliminations and the Partnership’s consolidated accounts as of March 31, 2013 and December 31, 2012 and for the three months ended March 31, 2013 and 2012. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting (in thousands):

 

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Balance Sheets

 

      Parent      Guarantor
Subsidiaries
     Non-
Guarantor
Subsidiaries
     Consolidating
Adjustments
    Consolidated  

March 31, 2013

             
Assets              

Cash and cash equivalents

   $ —         $ 157       $ 8,104       $ —        $ 8,261   

Accounts receivable – affiliates

     382,018         —           —           (382,018     —     

Other current assets

     210         83,142         134,621         (1,120     216,853   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total current assets

     382,228         83,299         142,725         (383,138     225,114   

Property, plant and equipment, net

     —           497,992         1,801,975         —          2,299,967   

Intangible assets, net

     —           91,099         91,687         —          182,786   

Goodwill

     —           278,423         40,862         —          319,285   

Equity method investment in joint venture

     —           86,242         —           —          86,242   

Long term portion of derivative asset

     —           2,378         —           —          2,378   

Long term notes receivable

     —           —           1,852,928         (1,852,928     —     

Equity investments

     2,451,114         1,546,753         —           (3,997,867     —     

Other assets, net

     36,686         1,772         200         —          38,658   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

   $ 2,870,028       $ 2,587,958       $ 3,930,377       $ (6,233,933   $ 3,154,430   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
Liabilities and Equity              

Accounts payable – affiliates

   $ —         $ 275,492       $ 110,864       $ (382,018   $ 4,338   

Other current liabilities

     5,531         81,035         161,155         —          247,721   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total current liabilities

     5,531         356,527         272,019         (382,018     252,059   

Long-term debt, less current portion

     1,309,563         488         —           —          1,310,051   

Long-term portion of derivative liability

     —           925         —           —          925   

Deferred income taxes, net

     —           30,249         —           —          30,249   

Other long-term liability

     146         212         6,000         —          6,358   

Equity

     1,554,788         2,199,557         3,652,358         (5,851,915     1,554,788   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities and equity

   $ 2,870,028       $ 2,587,958       $ 3,930,377       $ (6,233,933   $ 3,154,430   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

December 31, 2012

  
Assets              

Cash and cash equivalents

   $ —         $ 157       $ 3,241       $ —        $ 3,398   

Accounts receivable – affiliates

     921,702         —           —           (921,702     —     

Other current assets

     172         68,144         149,507         (1,146     216,677   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total current assets

     921,874         68,301         152,748         (922,848     220,075   

Property, plant and equipment, net

     —           491,790         1,708,591         —          2,200,381   

Intangible assets, net

     —           101,446         97,914         —          199,360   

Goodwill

     —           278,423         40,862         —          319,285   

Equity method investment in joint venture

     —           86,002         —           —          86,002   

Long term portion of derivative asset

     —           7,942         —           —          7,942   

Long term notes receivable

     —           —           1,852,928         (1,852,928     —     

Equity investments

     1,832,652         1,880,155         —           (3,712,807     —     

Other assets, net

     30,496         1,772         325         —          32,593   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

   $ 2,785,022       $ 2,915,831       $ 3,853,368       $ (6,488,583   $ 3,065,638   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
Liabilities and Equity              

Accounts payable – affiliates

   $ —         $ 145,436       $ 781,766       $ (921,702   $ 5,500   

Other current liabilities

     10,046         61,333         176,640         —          248,019   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total current liabilities

     10,046         206,769         958,406         (921,702     253,519   

Long-term debt, less current portion

     1,168,415         604         64         —          1,169,083   

Deferred income taxes, net

     —           30,258         —           —          30,258   

Other long-term liability

     153         217         6,000         —          6,370   

Equity

     1,606,408         2,677,983         2,888,898         (5,566,881     1,606,408   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities and equity

   $ 2,785,022       $ 2,915,831       $ 3,853,368       $ (6,488,583   $ 3,065,638   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

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Statements of Operations

 

      Parent     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Consolidating
Adjustments
    Consolidated  
            

Three Months Ended March 31, 2013

  

Total revenues

   $ —        $ 91,841      $ 335,372      $ (19,301   $ 407,912   

Total costs and expenses

     (18,596     (114,227     (297,349     19,301        (410,871

Equity income

     16,317        38,695        —          (52,972     2,040   

Loss on early extinguishment of debt

     (26,582     —          —          —          (26,582
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss), before tax

     (28,861     16,309        38,023        (52,972     (27,501

Income tax benefit

     —          (9     —          —          (9
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     (28,861     16,318        38,023        (52,972     (27,492

Income attributable to non-controlling interest

     —          —          (1,369     —          (1,369
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners and the General Partner

   $ (28,861   $ 16,318      $ 36,654      $ (52,972   $ (28,861
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Three Months Ended March 31, 2012

  

Total revenues

   $ —        $ 48,987      $ 243,299      $ —        $ 292,286   

Total costs and expenses

     (8,350     (70,083     (208,278     —          (286,711

Equity income

     13,285        34,904        —          (47,293     896   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     4,935        13,808        35,021        (47,293     6,471   

Income attributable to non-controlling interest

     —          —          (1,536     —          (1,536
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners and the General Partner

     4,935        13,808        33,485        (47,293     4,935   

Other comprehensive income adjustment for realized losses on derivatives reclassified to net income

     1,146        1,146        —          (1,146     1,146   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

   $ 6,081      $ 14,954      $ 33,485      $ (48,439   $ 6,081   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statements of Cash Flows

  

Three Months Ended March 31, 2013

  

Net cash provided by (used in):

          

Operating activities

   $ (58,592   $ 33,933      $ 56,426      $ 3,489      $ 35,256   

Investing activities

     (21,541     (2,534     (105,856     21,541        (108,390

Financing activities

     80,133        (31,399     54,293        (25,030     77,997   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net change in cash and cash equivalents

     —          —          4,863        —          4,863   

Cash and cash equivalents, beginning of period

     —          157        3,241        —          3,398   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ —        $ 157      $ 8,104      $ —        $ 8,261   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Three Months Ended March 31, 2012

  

Net cash provided by (used in):

          

Operating activities

   $ (63,078   $ 31,874      $ 43,327      $ 30,624      $ 42,747   

Investing activities

     7,010        54,442        (82,786     (76,942     (98,276

Financing activities

     56,068        (86,316     39,459        46,318        55,529   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net change in cash and cash equivalents

     —          —          —          —          —     

Cash and cash equivalents, beginning of period

     —          168        —          —          168   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ —        $ 168      $ —        $ —        $ 168   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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NOTE 18 – SUBSEQUENT EVENTS

On April 16, 2013, Atlas Pipeline Mid-Continent Holdings, LLC, a wholly owned subsidiary of the Partnership, entered into a definitive agreement with TEAK Midstream Holdings, LLC and its wholly owned subsidiary TEAK Midstream, L.L.C. (“TEAK”) to purchase 100% of the outstanding ownership interests in TEAK for $1.0 billion in cash, subject to customary purchase price adjustments (the “TEAK Acquisition”). TEAK’s assets primarily include gas gathering, processing and treating facilities in South Texas. Closing of the pending TEAK Acquisition is subject to customary closing conditions and is expected to occur in May 2013, with an effective date of April 1, 2013.

On April 16, 2013, the Partnership executed a Class D preferred unit purchase agreement for a private placement of $400.0 million of its Class D convertible preferred units (“Class D Preferred Units”) to third party investors, at a negotiated price per unit of $30.41, subject to adjustment. The Class D Preferred Units will be offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The issuance of the Class D Preferred Units is subject to customary closing conditions and is conditioned upon the closing of the TEAK Acquisition. The Partnership will have the right to convert the Class D Preferred Units, in whole but not in part, beginning one year following their issuance, into common units, subject to customary anti-dilution adjustments. Unless previously converted, all Class D Preferred Units will convert into common units at the end of eight full quarterly periods following their issuance. The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of the Partnership’s General Partner. Distributions will be determined based upon the cash distribution declared each quarter on the Partnership’s common limited partner units. Upon the issuance of the Class D Preferred Units the Partnership will enter into a registration rights agreement pursuant to which it will agree to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class D Preferred Units. The Partnership will agree to use its commercially reasonable efforts to have the registration statement declared effective within 180 days of the date of conversion. The General Partner will also contribute $8.2 million to maintain its 2% general partnership interest, upon the issuance of the Class D Preferred Units. The Partnership expects to use all of the proceeds to fund a portion of the purchase price of the TEAK Acquisition.

On April 17, 2013, the Partnership entered into an underwriting agreement for the sale and issuance of 11,845,000 common units of the Partnership (including 1,545,000 common units to cover the underwriters’ over-allotment option) at a price to the public of $34.00 per unit. The underwriters exercised their over-allotment option in full on April 18, 2013. The Partnership received $388.4 million in proceeds after underwriting commissions and estimated expenses, plus the General Partner contributed $8.3 million to maintain its 2% general partnership interest. The Partnership expects to use all of the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition.

On April 19, 2013, the Partnership entered into an amendment to its credit agreement, which, among other changes, (1) allowed the pending TEAK Acquisition to be a Permitted Investment, as defined in the credit agreement; (2) will not require the joint venture interests, which will be acquired in the pending TEAK Acquisition, to be guarantors; (3) modified the definitions of Consolidated Funded Debt Ratio, Interest Coverage Ratio and Consolidated EBITDA to allow for an Acquisition Period whereby the terms for calculating each of these ratios have been adjusted; and (4) permitted the payment of cash distributions, if any, on the Class D Preferred Units so long as the Partnership has a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million.

On April 24, 2013, the Partnership declared a cash distribution of $0.59 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended March 31, 2013. The $49.3 million distribution, including $4.0 million to the General Partner for its general partner interest and incentive distribution rights, will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013 (see Note 4).

 

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Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A, under the caption “Risk Factors”, in our Annual Report on Form 10-K for the year ended December 31, 2012. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

General

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report and with our Annual Report on Form 10-K for the year ended December 31, 2012.

Overview

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” We are a leading provider of natural gas gathering, processing and treating services in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States; a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and a provider of NGL transportation services in the southwestern region of the United States.

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Gathering and Processing; and Transportation and Treating.

The Gathering and Processing segment consists of (1) the Arkoma, WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko, Arkoma and Permian Basins; and (2) natural gas gathering assets located in the Barnett Shale play in Texas and the Appalachian Basin in Tennessee. Gathering and Processing revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas.

As of March 31, 2013, our Gathering and Processing operations, own, have interests in and operate twelve natural gas processing plants with aggregate capacity of approximately 1,090 MMCFD located in Oklahoma and Texas; a gas treating facility located in Oklahoma; and approximately 10,100 miles of active natural gas gathering systems located in Oklahoma, Kansas, Tennessee and Texas. Our gathering systems gather natural gas from oil and natural gas wells and central delivery points and deliver to this gas to processing plants, as well as third-party pipelines.

 

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Our Gathering and Processing operations are all located in or near areas of abundant and long-lived natural gas production, including the Golden Trend, Mississippian Limestone and Hugoton field in the Anadarko Basin; the Woodford Shale; the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin; and the Barnett Shale. Our gathering systems are connected to approximately 8,600 receipt points, consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells. We believe we have significant scale in each of our primary service areas. We provide gathering, processing and treating services to the wells connected to our systems, primarily under long-term contracts. As a result of the location and capacity of our gathering, processing and treating assets, we believe we are strategically positioned to capitalize on the drilling activity in our service areas.

Our Transportation and Treating operations consist of (1) seventeen gas treating facilities used to provide contract treating services to natural gas producers located in Arkansas, Louisiana, Oklahoma and Texas; and (2) a 20% interest in WTLPG, which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The contract gas treating operations are located in various shale plays, including the Avalon, Eagle Ford, Granite Wash, Haynesville, Fayetteville and Woodford. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation (“Chevron” NYSE: CVX), which owns the remaining 80% interest.

Recent Events

On January 7, 2013, we paid $6.0 million for the first of two contingent payments related to the acquisition of a gas gathering system and related assets in February 2012. We agreed to pay up to an additional $12.0 million, payable in two equal amounts, if certain volumes were achieved on the acquired gathering system within specified periods of time. Sufficient volumes were achieved in December 2012 to meet the required volumes for the first contingent payment.

On February 11, 2013, we issued $650.0 million of 5.875% unsecured senior notes due August 1, 2023 (“5.875% Senior Notes”) in a private placement transaction. The 5.875% Senior Notes were issued at par. We received net proceeds of $637.1 million and utilized the proceeds to redeem our outstanding 8.75% senior unsecured notes due June 15, 2018 (“8.75% Senior Notes”) and repay a portion of our outstanding indebtedness under our revolving credit facility.

Prior to issuance of the 5.875% Senior Notes and in anticipation thereof, on January 28, 2013, we commenced a cash tender offer for any and all of our outstanding $365.8 million 8.75% Senior Notes, and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% Senior Notes (“8.75% Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% Senior Notes (representing approximately 73.4% of the outstanding 8.75% Senior Notes), were validly tendered as of the expiration date of the consent solicitation. In February 2013, we accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent solicitation and entered into a supplemental indenture amending and supplementing the 8.75% Senior Notes Indenture. We also issued a notice to redeem all the 8.75% Senior Notes not purchased in connection with the tender offer.

On March 12, 2013, we paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% Senior Notes plus a $6.3 million make-whole premium and $2.0 million in accrued interest. We funded the redemption with a portion of the net proceeds from the issuance of the 5.875% Senior Notes.

 

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Subsequent Events

On April 16, 2013 we entered into a definitive agreement with TEAK Midstream Holdings, LLC and its wholly owned subsidiary TEAK Midstream, L.L.C. (“TEAK”) to purchase 100% of the outstanding ownership interests in TEAK for $1.0 billion in cash, subject to customary purchase price adjustments (the “TEAK Acquisition”). TEAK’s assets primarily include gas gathering, processing and treating facilities in South Texas. Closing of the pending TEAK Acquisition is subject to customary closing conditions and is expected to occur in May 2013, with an effective date of April 1, 2013.

On April 16, 2013, we executed a Class D preferred unit purchase agreement for a private placement of $400 million of Class D convertible preferred units (“Class D Preferred Units”) to third party investors, at a negotiated price per unit of $30.41, subject to adjustment. The Class D Preferred Units will be offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The issuance of the Class D Preferred Units is subject to customary closing conditions, conditioned upon the closing of the TEAK Acquisition. We will have the right to convert the Class D Preferred Units, in whole but not in part, beginning one year following their issuance, into common units, subject to customary anti-dilution adjustments. Unless previously converted, all Class D Preferred Units will convert into common units at the end of eight full quarterly periods following their issuance. The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of our General Partner. Distributions will be determined based upon the cash distribution declared each quarter for payment on our common limited partner units. Upon the issuance of the Class D Preferred Units, we will enter into a registration rights agreement pursuant to which we will agree to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class D Preferred Units. We will agree to use its commercially reasonable efforts to have the registration statement declared effective within 180 days of the date of conversion. The General Partner will also contribute $8.2 million to maintain its 2% general partnership interest, upon the issuance of the Class D Preferred Units. We expect to use all of the proceeds to fund a portion of the purchase price of the TEAK Acquisition.

On April 17, 2013, we entered into an underwriting agreement for the sale and issuance of 11,845,000 of our common units (including 1,545,000 common units to cover the underwriters’ over-allotment option) at a price to the public of $34.00 per unit. The underwriters exercised their over-allotment option in full on April 18, 2013. We received $388.4 million in proceeds after underwriting commissions and estimated expenses, plus the General Partner contributed $8.3 million to maintain its 2% general partnership interest. We expect to use all of the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition.

On April 19, 2013, we entered into an amendment to our credit agreement, which among other changes:

 

   

allowed the pending TEAK Acquisition to be a Permitted Investment, as defined in the credit agreement;

 

   

will not require the joint venture interests, which will be acquired in the pending TEAK Acquisition, to be guarantors;

 

   

permitted the payment of cash distributions, if any, on the Class D Preferred Units so long as we have a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million; and

 

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modified the definition of Consolidated Funded Debt Ratio, Interest Coverage Ratio and Consolidated EBITDA to allow for an Acquisition Period whereby the terms for calculating each of these ratios have been adjusted; and

 

   

permitted the Consolidated Funded Debt Ratio to be greater than:

 

   

5.50 to 1.00 for the last day of any fiscal quarter during an Acquisition Period (as defined by the credit agreement);

 

   

5.75 to 1.00 for the last day of the fiscal quarter in which the TEAK Acquisition is consummated;

 

   

5.50 to 1.00 for last day of the two fiscal quarters immediately following the fiscal quarter in which the TEAK Acquisition is consummated; or

 

   

5.00 to 1.00 for the last day of any other fiscal quarter.

Acquisitions

In December 2012, we acquired 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.5 million in cash, including preliminary purchase price adjustments, less cash received (the “Cardinal Acquisition”). The assets of these companies represented the majority of the operating assets of Cardinal (the “Arkoma system”) and include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas as follows:

 

   

the Tupelo plant, which is a 120 MMCFD cryogenic processing facility;

 

   

approximately 60 miles of gathering pipeline;

 

   

the East Rockpile treating facility, a 250 GPM amine treating plant;

 

   

a fixed fee contract gas treating business that includes 15 amine treating plants and two propane refrigeration plants; and

 

   

a 60% interest in a joint venture known as Centrahoma Processing, LLC (“Centrahoma”). The remaining 40% interest is owned by MarkWest Oklahoma Gas Company, LLC, (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). Centrahoma owns the following assets:

 

   

the Coalgate and Atoka plants, which are cryogenic processing facilities with a combined current processing capacity of approximately 100 MMCFD;

 

   

the prospective Stonewall plant, for which construction has been approved, with anticipated processing capacity of 120 MMCFD; and

 

   

15 miles of NGL pipeline.

How We Evaluate Our Operations

Our principal revenue is generated from the gathering, processing and treating of natural gas and the sale of natural gas, NGLs and condensate. Our profitability is a function of the difference between the revenues we receive and the costs associated with conducting our operations, including the cost of natural gas, NGLs and condensate we purchase as well as operating and general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Variables that affect our profitability are:

 

   

the volumes of natural gas we gather, process and treat, which in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas the wells produce, and the demand for natural gas, NGLs and condensate;

 

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the price of the natural gas we gather, process and treat, and the NGLs and condensate we recover and sell, which is a function of the relevant supply and demand in the mid-continent and northeastern areas of the United States;

 

   

the NGL and BTU content of the gas gathered and processed;

 

   

the contract terms with each producer; and

 

   

the efficiency of our gathering systems and processing and treating plants.

Revenue consists of the sale of natural gas, NGLs and condensate; and the fees earned from our gathering, processing and treating operations. Under certain agreements, we purchase natural gas from producers and move it into receipt points on our pipeline systems and then sell the natural gas, NGLs and condensate off delivery points on our systems. Under other agreements, we gather natural gas across our systems, from receipt to delivery point, without taking title to the natural gas. (See “Item 1. Notes to Consolidated Financial Statements (Unaudited) –Note 2–Revenue Recognition” for further discussion of contractual revenue arrangements).

Our management uses a variety of financial measures and operational measurements other than our GAAP financial statements to analyze our performance. These include: (1) volumes, (2) operating expenses and (3) the following non-GAAP measures gross margin, EBITDA, adjusted EBITDA and distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.

Volumes. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our gathering, processing and treating systems. This is achieved by connecting new wells and adding new volumes in existing areas of production. Our performance at our plants is also significantly impacted by the quality of the natural gas we process, the NGL content of the natural gas and the plant’s recovery capability. In addition, we monitor fuel consumption and losses because they have a significant impact on the gross margin realized from our processing operations.

Operating Expenses. Plant operating, transportation and compression expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, ad valorem taxes and other overhead costs.

Gross Margins. We define gross margin as natural gas and liquids sales plus transportation, processing and other fees less purchased product costs, subject to certain non-cash adjustments. Product costs include the cost of natural gas, NGLs and condensate we purchase from third parties. Gross margin, as we define it, does not include plant operating expenses; transportation and compression expenses; and derivative gain (loss) related to undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories.

 

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Gross margin is a non-GAAP measure. The GAAP measure most directly comparable to gross margin is net income. Gross margin is not an alternative to GAAP net income and has important limitations as an analytical tool. Investors should not consider gross margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of gross margin may not be comparable to gross margin measures of other companies, thereby diminishing its utility.

EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) before interest expense, income taxes, depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, impairment charges and other cash items such as non-recurring cash derivative early termination expense. The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income. EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation is similar to the Consolidated EBITDA calculation utilized within the financial covenants under our credit facility, with the exception that Adjusted EBITDA includes certain non-cash items specifically excluded under our credit facility and excludes the capital expansion add back included in Consolidated EBITDA as defined in the credit facility (see “Revolving Credit Facility”).

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as indicators of our operating performance or liquidity. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. We define distributable cash flow as net income plus tax, depreciation and amortization; amortization of deferred financing costs included in interest expense; and non-cash gain (losses) on derivative contracts, less income attributable to non-controlling interests, preferred unit dividends, maintenance capital expenditures, gain (losses) on asset sales and other non-cash gain (losses).

Distributable cash flow is a significant performance metric used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can compute the ratio of distributable cash flow per unit to the declared cash distribution per unit to determine the rate at which the distributable cash flow covers the distribution. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit’s yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

 

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The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income or GAAP cash flows from operating activities. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measurements used by management to their most directly comparable GAAP measures for the three months ended March 31, 2013 and 2012 (in thousands):

RECONCILIATION OF GROSS MARGIN

 

     Three Months Ended  
     March 31,  
     2013     2012  

Net income (loss)

   $ (27,492   $ 6,471   

Adjustments:

    

Derivative loss, net

     12,083        12,035   

Other income, net

     (3,422     (2,415

Operating expenses(1)

     22,389        14,111   

General and administrative expense(2)

     13,798        9,945   

Depreciation and amortization

     30,458        20,842   

Interest

     18,686        8,708   

Income tax expense

     (9     —     

Equity income in joint venture

     (2,040     (896

Loss on early extinguishment of debt

     26,582        —     

Non-cash linefill (gain) loss(3)

     32        272   
  

 

 

   

 

 

 

Gross margin

   $ 91,065      $ 69,073   
  

 

 

   

 

 

 

 

(1) Operating expenses include plant operating expenses; transportation and compression expenses; and other costs.
(2) General and administrative includes compensation reimbursement to affiliates.
(3) Represents the non-cash impact of commodity price movements on pipeline linefill.

 

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RECONCILIATION OF EBITDA, ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW

 

     Three Months Ended  
     March 31,  
     2013     2012  

Net income (loss)

   $ (27,492   $ 6,471   

Adjustments:

    

Income attributable to non-controlling interests(1)

     (1,369     (1,536

Interest expense

     18,686        8,708   

Income tax benefit

     (9     —     

Depreciation and amortization

     30,458        20,842   

Non-controlling interest depreciation, amortization and interest expense(2)

     (850     —     
  

 

 

   

 

 

 

EBITDA

     19,424        34,485   

Adjustments:

    

Equity income in joint venture

     (2,040     (896

Distributions from joint venture

     1,800        1,800   

Loss on early extinguishment of debt

     26,582        —     

Non-cash loss on derivatives

     13,719        10,696   

Premium expense on derivative instruments

     3,275        3,752   

Acquisitions costs

     530        —     

Non-cash compensation

     4,384        978   

Non-cash line fill (gain) loss(3)

     32        272   
  

 

 

   

 

 

 

Adjusted EBITDA

     67,706        51,087   

Adjustments:

    

Interest expense

     (18,686     (8,708

Amortization of deferred finance costs

     1,544        1,165   

Premium expense on derivative instruments

     (3,275     (3,752

Other costs

     —          (34

Maintenance capital(4)

     (3,814     (4,510
  

 

 

   

 

 

 

Distributable Cash Flow

   $ 43,475      $ 35,248   
  

 

 

   

 

 

 

 

(1) Represents Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) non-controlling interest in the operating results of Atlas Pipeline Mid-Continent WestOk, LLC (“WestOK”) and Atlas Pipeline Mid-Continent WestTex, LLC (“WestTX”); and MarkWest’s non-controlling interest in Centrahoma.
(2) Represents the depreciation, amortization and interest expense included in income attributable to non-controlling interest for MarkWest’s interest in Centrahoma.
(3) Represents the non-cash impact of commodity price movements on pipeline linefill.
(4) Represents maintenance capital expenditures net of amounts attributable to non-controlling interest for MarkWest’s interest in Centrahoma.

 

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Results of Operations

The following table illustrates selected pricing before the effect of derivatives and volumetric information for the periods indicated:

 

     Three Months Ended         
     March 31,      Percent
Change
 
     2013      2012     

Pricing:

        

Weighted Average Market Prices:

        

NGL price per gallon – Conway hub

   $ 0.83       $ 0.93         (10.8 )% 

NGL price per gallon – Mt. Belvieu hub

     0.85         1.18         (28.0 )% 

Natural gas sales ($/Mcf):

  

Velma

     3.17         2.55         24.3

WestOK

     3.20         2.56         25.0

WestTX

     3.12         2.51         24.3

Weighted Average

     3.17         2.54         24.8

NGL sales ($/gallon):

        

Arkoma

     0.70         —           —     

Velma

     0.75         0.93         (19.4 )% 

WestOK

     0.98         0.91         7.7

WestTX

     0.93         1.17         (20.5 )% 

Weighted Average

     0.84         1.03         (18.4 )% 

Condensate sales ($/barrel):

        

Arkoma

     87.92         —           —     

Velma

     93.39         102.22         (8.6 )% 

WestOK

     83.67         93.95         (10.9 )% 

WestTX

     88.02         101.38         (13.2 )% 

Weighted Average

     86.00         97.44         (11.7 )% 

 

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     Three Months Ended
March 31,
     Percent
Change
 
     2013      2012     

Operating data:

        

Arkoma system(1):

        

Gathered gas volume (MCFD)

     260,732         —           —     

Processed gas volume (MCFD)

     201,301         —           —     

Residue gas volume (MCFD)

     207,844         —           —     

NGL volume (BPD)

     20,555         —           —     

Condensate volume (BPD)

     158         —           —     

Velma system:

        

Gathered gas volume (MCFD)

     130,767         129,223         1.2

Processed gas volume (MCFD)

     125,377         122,904         2.0

Residue gas volume (MCFD)

     102,238         100,335         1.9

NGL volume (BPD)

     13,997         13,643         2.6

Condensate volume (BPD)

     405         564         (28.2 )% 

WestOK system:

        

Gathered gas volume (MCFD)

     452,368         295,198         53.2

Processed gas volume (MCFD)

     425,431         279,305         52.3

Residue gas volume (MCFD)

     396,694         251,940         57.5

NGL volume (BPD)

     16,251         14,062         15.6

Condensate volume (BPD)

     1,969         1,405         40.1

WestTX system(1):

        

Gathered gas volume (MCFD)

     312,571         246,339         26.9

Processed gas volume (MCFD)

     280,756         230,504         21.8

Residue gas volume (MCFD)

     209,891         160,022         31.2

NGL volume (BPD)

     33,245         33,101         0.4

Condensate volume (BPD)

     1,033         939         10.0

Barnett system:

        

Average throughput volumes (MCFD)

     21,401         —           —     

Tennessee system:

        

Average throughput volumes (MCFD)

     9,495         8,225         15.4

WTLPG system(1):

        

Average NGL volumes (BPD)

     244,626         242,318         1.0

 

(1) Operating data for Arkoma, WestTX and WTLPG represent 100% of operating activity for the respective systems. Arkoma gathered volumes include volumes gathered by MarkWest and processed through the Arkoma facilities.

 

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The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2013 and 2012 (in thousands):

 

     Three Months Ended
March 31,
          Percent  
     2013     2012     Variance     Change  

Gross margin(1)

        

Natural gas and liquids sales

   $ 383,848      $ 289,225      $ 94,623        32.7

Transportation, processing and other fees

     32,725        12,681        20,044        158.1

Less: non-cash line fill gain (loss)(2)

     (32     (272     240        88.2

Less: natural gas and liquids cost of sales

     325,540        233,105        92,435        39.7
  

 

 

   

 

 

   

 

 

   

Gross margin

     91,065        69,073        21,992        31.8

Expenses:

        

Operating expenses

     21,859        14,145        7,714        54.5

General and administrative(3)

     13,798        9,945        3,853        38.7

Other costs

     530        (34     564        1658.8

Depreciation and amortization

     30,458        20,842        9,616        46.1

Interest expense

     18,686        8,708        9,978        114.6
  

 

 

   

 

 

   

 

 

   

Total expenses

     85,331        53,606        31,725        59.2

Other income items:

        

Derivative loss, net

     (12,083     (12,035     (48     (0.4 )% 

Other income, net

     3,422        2,415        1,007        41.7

Non-cash line fill gain (loss)(2)

     (32     (272     240        88.2

Equity income in joint venture

     2,040        896        1,144        127.7

Loss on early extinguishment of debt

     (26,582     —          (26,582     (100.0 )% 

Income tax benefit

     9        —          9        100.0

Income attributable to non-controlling interests(4)

     (1,369     (1,536     167        10.9
  

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to common limited partners and General Partner

   $ (28,861   $ 4,935      $ (33,796     (684.8 )% 
  

 

 

   

 

 

   

 

 

   

Non-GAAP financial data:

        

EBITDA(1)

   $ 19,424      $ 34,485      $ (15,061     (43.7 )% 

Adjusted EBITDA(1)

     67,706        51,087        16,619        32.5

Distributable cash flow(1)

     43,475        35,248        8,227        23.3

 

(1) Gross Margin, EBITDA, Adjusted EBITDA and Distributable cash flow are non-GAAP financial measures (see “How We Evaluate Our Operations” and “Non-GAAP Financial Measures”).
(2) Includes the non-cash impact of commodity price movements on pipeline linefill.
(3) General and administrative also includes any compensation reimbursement to affiliates.
(4) Represents Anadarko’s non-controlling interest in the operating results of the WestOK and WestTX systems and MarkWest’s non-controlling interest in the operating results of Centrahoma.

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Gross margin:

Gross margin from natural gas and liquids sales and the related natural gas and liquids cost of sales for the three months ended March 31, 2013 increased primarily due to higher production volumes, including the new volumes from the Arkoma system due to the Cardinal Acquisition, partially offset by lower commodity prices.

 

   

Volumes on the Velma system for the three months ended March 31, 2013 approximated the prior year period volumes.

 

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Volumes on the WestOK system increased for the three months ended March 31, 2013 compared to the prior year primarily due to increased production on the gathering systems, which continue to be expanded to meet producer demand; and the start-up of the Waynoka II plant.

 

   

WestTX system gathering and processing volumes for the three months ended March 31, 2013 increased compared to the prior year period due to increased volumes from Pioneer Natural Resources Company (NYSE: PXD) as a result of their continued drilling program.

Transportation, processing and other fees for the three months ended March 31, 2013 increased primarily due to $12.9 million in additional fee-based revenues generated on the Arkoma systems acquired in December 2012 (see “Acquisitions”) and due to increased processing fee revenue of $5.6 million on the WestOK system related to the increased volumes gathered on the systems.

Expenses:

Operating expenses, comprised primarily of plant operating expenses and transportation and compression expenses, for the three months ended March 31, 2013 increased mainly due to $3.6 million in additional expenses from the Arkoma systems and a $2.8 million increase on the WestOK system primarily due to increased gathered volumes in comparison to the prior year period, as discussed above in “Gross margin.”

General and administrative expense, including amounts reimbursed to affiliates, increased for the three months ended March 31, 2013 mainly due to a $3.4 million increase in share-based compensation related to phantom units granted to employees (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) –Note 14”).

Other costs for the three months ended March 31, 2013 increased mainly due to $0.5 million in acquisition costs related to the Cardinal Acquisition, which were recorded in the current year period (see “Acquisitions”).

Depreciation and amortization expense for the three months ended March 31, 2013 increased primarily due to $5.7 million additional expense related to assets acquired the Cardinal Acquisition (see “Acquisitions”) and due to growth capital expenditures incurred subsequent to March 31, 2012.

Interest expense for the three months ended March 31, 2013 increased primarily due to an $8.2 million increase in interest expense associated with the 6.625% unsecured senior notes due October 1, 2020 (“6.625% Senior Notes) and $5.3 million additional interest related to the 5.875% Senior Notes, partially offset by $3.6 million reduced interest on the 8.75% Senior Notes. The increase in the interest on the 6.625% Senior Notes and the 5.875% Senior Notes is due to their issuance after March 31, 2012 (see “Senior Notes”). The decrease in the interest for the 8.75% Senior Notes is due to their redemption during the three months ended March 31, 2013 (see “Senior Notes”).

Other income items:

Derivative gain (loss), net for the three months ended March 31, 2013 had a $2.4 million favorable variance for realized settlements in the current period compared to the prior year period mainly as a result of lower NGL prices, offset by a $2.4 million unfavorable variance on the fair value revaluation of commodity derivative contracts in the current period compared to the prior year period.

 

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While we utilize either quoted market prices or observable market data to calculate the fair value of natural gas and crude oil derivatives, valuations of NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGLs for similar geographic locations, and valuations of NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for NGL fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact net income, although it would have no impact on liquidity or capital resources (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) –Note 9” for further discussion of derivative instrument valuations). We recognized a $2.4 million and $7.1 million mark-to-market loss on derivatives that were valued based upon unobservable inputs for the three months ended March 31, 2013 and 2012, respectively. We enter into derivative instruments solely to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under “Item 3: Quantitative and Qualitative Disclosures About Market Risk.”

Other income, net for the three months ended March 31, 2013 had a favorable variance primarily due to a $1.0 million settlement of business interruption insurance related to a loss of revenue in our WestOK system in May 2011 due to storm damage at the Chester plant.

Non-cash line fill gain (loss) had a favorable variance for the three months ended March 31, 2013 compared to the prior year period primarily due to the settlement of line fill on the Velma system during the prior year period.

Equity income in joint venture increased for the three months ended March 31, 2013 primarily due to increased revenues from our 20% ownership interest in WTPLG mainly as a result of a tariff rate increase after March 31, 2012.

Loss on early extinguishment of debt for the three months ended March 31, 2013 represents $17.5 million premiums paid; $8.0 million consent payment made; and $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium related to the redemption of the 8.75% Senior Notes (see “Senior Notes”).