10-Q 1 a2198585z10-q.htm 10-Q

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM 10-Q

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

For the quarterly period ended March 31, 2010

OR

o

 

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

For the transition period from                             to                            

Commission File Number 001-31239



MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

Delaware   27-0005456
(State or other jurisdiction of
incorporation or organization)
  (IRS Employer
Identification No.)

1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202-2126
(Address of principal executive offices)

Registrant's telephone number, including area code: 303-925-9200

        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 ý    Noo

        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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller
reporting company)
  Smaller reporting company o

        Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2 of the Exchange Act). Yes o    No ý

        The number of the registrant's common units outstanding as of May 3, 2010, was 71,433,372.


Table of Contents

PART I—FINANCIAL INFORMATION

   

Item 1.

 

Financial Statements

 
2

 

Unaudited Condensed Consolidated Balance Sheets at March 31, 2010 and December 31, 2009

 
2

 

Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2010 and 2009

 
3

 

Unaudited Condensed Consolidated Statements of Changes in Equity for the three months ended March 31, 2010 and 2009

 
4

 

Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2010 and 2009

 
5

 

Unaudited Notes to the Condensed Consolidated Financial Statements

 
6

Item 2.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

 
34

Item 3.

 

Quantitative and Qualitative Disclosures about Market Risk

 
47

Item 4.

 

Controls and Procedures

 
47

PART II—OTHER INFORMATION

   

Item 1.

 

Legal Proceedings

 
49

Item 6.

 

Exhibits

 
49

SIGNATURES

 
50

        Throughout this document we make statements that are classified as "forward-looking." Please refer to the "Forward-Looking Statements" included in Part I, Item 2 for an explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to "we," "us," "our," "MarkWest Energy" or the "Partnership" are intended to mean MarkWest Energy Partners, L.P., and its consolidated subsidiaries. References to "MarkWest Hydrocarbon" or the "Corporation" are intended to mean MarkWest Hydrocarbon, Inc., a wholly-owned taxable subsidiary of the Partnership.


Table of Contents

Glossary of Terms

Bbl

  Barrel

Bbl/d

 

Barrels per day

Btu

 

One British thermal unit, an energy measurement

Dth/d

 

Dekatherms per day

FASB

 

Financial Accounting Standards Board

FERC

 

Federal Energy Regulatory Commission

GAAP

 

Accounting principles generally accepted in the United States of America

Gal

 

Gallon

Gal/d

 

Gallons per day

LIBOR

 

London Interbank Offered Rate

Mcf/d

 

One thousand cubic feet of natural gas per day

MMBtu

 

One million British thermal units, an energy measurement

MMBtu/d

 

One million British thermal units per day

MMcf/d

 

One million cubic feet of natural gas per day

Net operating margin (a non-GAAP financial measure)

 

Revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss)

NGL

 

Natural gas liquids, such as ethane, propane, butanes and natural gasoline

N/A

 

Not applicable

OTC

 

Over-the-Counter

SEC

 

Securities and Exchange Commission

VIE

 

Variable interest entity

VIEB

 

An asset balance attributable to consolidated VIEs that can only be used to settle obligations of the consolidated VIEs or a liability balance attributable to consolidated VIEs for which creditors or beneficial interest holders do not have recourse to the general credit of the Partnership

2002 LTIP

 

2002 Long-Term Incentive Plan

2006 Hydrocarbon Plan

 

2006 Hydrocarbon Stock Incentive Plan

2008 LTIP

 

2008 Long-Term Incentive Plan

1


Table of Contents


PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements


MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

 
  March 31, 2010   December 31, 2009  

ASSETS

             

Current assets:

             
 

Cash and cash equivalents, including VIEB of $54,944 and $21,942, respectively

  $ 105,175   $ 97,752  
 

Receivables, net, including VIEB of $27,845 and $22,033, respectively

    147,237     140,969  
 

Inventories, including VIEB of $2,243 and $3,343, respectively

    19,926     29,075  
 

Fair value of derivative instruments

    8,002     8,821  
 

Deferred income taxes

    12,228     12,228  
 

Other current assets, including VIEB of $360 and $327, respectively

    4,578     10,674  
           
   

Total current assets

    297,146     299,519  
           

Property, plant and equipment, including VIEB of $552,309 and $494,918, respectively

    2,248,762     2,154,644  

Less: accumulated depreciation, including VIEB of $16,854 and $11,324, respectively

    (201,092 )   (173,000 )
           
   

Total property, plant and equipment, net

    2,047,670     1,981,644  
           

Other long-term assets:

             
 

Investment in unconsolidated affiliate

    29,565     29,633  
 

Intangibles, net of accumulated amortization of $93,928 and $83,735, respectively

    644,218     654,411  
 

Goodwill

    9,421     9,421  
 

Deferred financing costs, net of accumulated amortization of $8,034 and $6,990, respectively

    19,984     21,027  
 

Deferred contract cost, net of accumulated amortization of $1,716 and $1,638, respectively

    1,534     1,612  
 

Fair value of derivative instruments

    9,968     15,810  
 

Other long-term assets, including VIEB of $300 and $314, respectively

    1,624     1,660  
           
   

Total assets

  $ 3,061,130   $ 3,014,737  
           

LIABILITIES AND EQUITY

             

Current liabilities:

             
 

Accounts payable, including VIEB of $6,426 and $2,745, respectively

  $ 112,639   $ 87,832  
 

Accrued liabilities, including VIEB of $50,199 and $44,615, respectively

    139,190     137,687  
 

Fair value of derivative instruments

    63,544     60,464  
           
   

Total current liabilities

    315,373     285,983  
           

Deferred income taxes

    9,662     11,034  

Fair value of derivative instruments

    55,103     62,519  

Long-term debt, net of discounts of $37,828 and $39,417, respectively

    1,165,306     1,170,072  

Other long-term liabilities, including VIEB of $372 and $365, respectively

    108,486     105,736  

Commitments and contingencies (Note 9)

             

Equity:

             
 

MarkWest Energy Partners, L.P. partners' capital (66,546 and 66,275 common units outstanding, respectively)

    1,079,017     1,096,654  
 

Non-controlling interest in consolidated subsidiaries

    328,183     282,739  
           
   

Total equity

    1,407,200     1,379,393  
           
   

Total liabilities and equity

  $ 3,061,130   $ 3,014,737  
           

The accompanying notes are an integral part of these condensed consolidated financial statements.

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

 
  Three months ended
March 31,
 
 
  2010   2009  

Revenue:

             
 

Revenue

  $ 315,615   $ 183,367  
 

Derivative (loss) gain

    (7,236 )   8,304  
           
   

Total revenue

    308,379     191,671  
           

Operating expenses:

             
 

Purchased product costs

    144,296     102,314  
 

Derivative loss related to purchased product costs

    13,389     29,513  
 

Facility expenses

    37,905     31,444  
 

Derivative gain related to facility expenses

    (806 )   (371 )
 

Selling, general and administrative expenses

    21,508     15,927  
 

Depreciation

    28,187     20,943  
 

Amortization of intangible assets

    10,193     10,233  
 

(Gain) loss on disposal of property, plant and equipment

    (9 )   729  
 

Accretion of asset retirement obligations

    143     47  
           
   

Total operating expenses

    254,806     210,779  
           
   

Income (loss) from operations

    53,573     (19,108 )

Other income (expense):

             
 

Loss from unconsolidated affiliates

    (68 )   (105 )
 

Interest income

    386     41  
 

Interest expense

    (23,782 )   (17,782 )
 

Amortization of deferred financing costs and discount (a component of interest expense)

    (2,612 )   (1,391 )
 

Derivative gain related to interest expense

    1,871      
 

Miscellaneous income (expense), net

    1,062     (662 )
           
   

Income (loss) before provision for income tax

    30,430     (39,007 )

Provision for income tax expense (benefit):

             
 

Current

    5,798     6,253  
 

Deferred

    (1,372 )   (15,591 )
           
   

Total provision for income tax

    4,426     (9,338 )
           
   

Net income (loss)

    26,004     (29,669 )

Net (income) loss attributable to non-controlling interest

    (4,494 )   20  
           
   

Net income (loss) attributable to the Partnership

  $ 21,510   $ (29,649 )
           

Net income (loss) attributable to the Partnership's common unitholders per common unit (Note 12):

             
 

Basic

  $ 0.32   $ (0.53 )
           
 

Diluted

  $ 0.32   $ (0.53 )
           

Weighted average number of outstanding common units:

             
 

Basic

    66,453     56,806  
           
 

Diluted

    66,453     56,806  
           

Cash distribution declared per common unit

  $ 0.64   $ 0.64  
           

The accompanying notes are an integral part of these condensed consolidated financial statements.

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Changes in Equity

(unaudited, in thousands)

 
  MarkWest Energy
Partners, L.P.
Unitholders
   
   
 
 
  Common
Units
  Partners'
Capital
  Non-controlling
Interest
  Total  

December 31, 2009

    66,275   $ 1,096,654   $ 282,739   $ 1,379,393  

Share-based compensation activity

    271     3,622         3,622  

Excess tax benefits related to share-based compensation

        97         97  

Distributions paid

        (42,866 )   (1,270 )   (44,136 )

Contributions to MarkWest Liberty Midstream joint venture, net

            42,220     42,220  

Net income

        21,510     4,494     26,004  
                   

March 31, 2010

    66,546   $ 1,079,017   $ 328,183   $ 1,407,200  
                   

 

 
  MarkWest Energy
Partners, L.P.
Unitholders
   
   
 
 
  Common
Units
  Partners'
Capital
  Non-controlling
Interest
  Total  

December 31, 2008

    56,640   $ 1,204,458   $ 3,301   $ 1,207,759  

Share-based compensation activity

    254     1,762         1,762  

Distributions paid

        (36,803 )       (36,803 )

Contributions to MarkWest Liberty Midstream joint venture, net

        (5,464 )   50,000     44,536  

Net loss

        (29,649 )   (20 )   (29,669 )
                   

March 31, 2009

    56,894   $ 1,134,304   $ 53,281   $ 1,187,585  
                   

The accompanying notes are an integral part of these condensed consolidated financial statements.

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)

 
  Three months ended
March 31,
 
 
  2010   2009  

Cash flows from operating activities:

             

Net income (loss)

  $ 26,004   $ (29,669 )
 

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

             
   

Depreciation

    28,187     20,943  
   

Amortization of intangible assets

    10,193     10,233  
   

Amortization of deferred financing costs and discount

    2,612     1,391  
   

Accretion of asset retirement obligations

    143     47  
   

Amortization of deferred contract cost

    78     78  
   

Phantom unit compensation expense

    6,285     2,703  
   

Equity in loss of unconsolidated affiliates

    68     105  
   

Unrealized loss on derivative instruments

    2,269     66,918  
   

(Gain) loss on disposal of property, plant and equipment

    (9 )   729  
   

Deferred income taxes

    (1,372 )   (15,591 )
   

Gain on sale of trading securities

        (40 )
   

Net sales of trading securities

        552  
 

Changes in operating assets and liabilities:

             
   

Receivables

    (5,968 )   21,531  
   

Inventories

    9,149     20,634  
   

Other current assets

    6,096     1,620  
   

Accounts payable and accrued liabilities

    28,507     (6,683 )
   

Other long-term assets

    36     (4,073 )
   

Other long-term liabilities

    2,082     392  
           
     

Net cash provided by operating activities

    114,360     91,820  
           

Cash flows from investing activities:

             
 

Capital expenditures

    (95,322 )   (168,942 )
 

Equity investments

        (4,984 )
 

Proceeds from disposal of property, plant and equipment

    292      
 

Change in restricted cash

        (1,125 )
           
     

Net cash flows used in investing activities

    (95,030 )   (175,051 )
           

Cash flows from financing activities:

             
 

Proceeds from revolving credit facility

    135,604     234,700  
 

Payments of revolving credit facility

    (141,904 )   (125,000 )
 

Payments for debt issuance costs, deferred financing costs and registration costs

        (4,323 )
 

Contributions to MarkWest Liberty Midstream joint venture, net

    42,220     44,536  
 

Payments of SMR liability

    (58 )    
 

Cash paid for taxes related to net settlement of share-based payment awards

    (3,730 )   (1,199 )
 

Excess tax benefits related to share-based compensation

    97      
 

Payment of distributions to common unitholders

    (42,866 )   (36,803 )
 

Payment of distributions to non-controlling interest

    (1,270 )    
           
     

Net cash flows (used in) provided by financing activities

    (11,907 )   111,911  
           

Net increase in cash

    7,423     28,680  

Cash and cash equivalents at beginning of year

    97,752     3,321  
           

Cash and cash equivalents at end of period

  $ 105,175   $ 32,001  
           

The accompanying notes are an integral part of these condensed consolidated financial statements.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1. Organization and Basis of Presentation

        MarkWest Energy Partners, L.P. was formed in January 2002 as a Delaware limited partnership. The Partnership is engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. The Partnership has extensive natural gas gathering, processing and transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor in the Appalachian region.

        These unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial statements should be read in conjunction with the Partnership's consolidated financial statements included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009. In management's opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, consider that results for the three months ended March 31, 2010 are not necessarily indicative of results for the full year 2010, or any other future period.

        The Partnership's unaudited condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Liberty Midstream & Resources L.L.C. ("MarkWest Liberty Midstream") and MarkWest Pioneer, L.L.C. ("MarkWest Pioneer"), variable interest entities for which the Partnership has been determined to be the primary beneficiary, are included in the condensed consolidated financial statements (see Note 3 for further discussion of MarkWest Liberty Midstream and MarkWest Pioneer). All significant intercompany investments, accounts and transactions have been eliminated. Investments in which the Partnership exercises significant influence but does not control, and is not the primary beneficiary, are accounted for using the equity method.

2. Recent Accounting Pronouncements

        In June 2009, the FASB amended the VIE subsections of the consolidation guidance. The amended guidance changes the criteria for determining if a VIE exists and whether or not a VIE should be consolidated. The amended guidance was effective for the Partnership on January 1, 2010, and the Partnership reconsidered its previous VIE conclusions and financial statement disclosures. The amendment had no effect on the Partnership's condensed consolidated financial statements.

        In September 2009, the FASB amended the accounting guidance for revenue recognition for multiple-deliverable arrangements. The amended guidance establishes a hierarchy for determining the selling price of each individual deliverable and eliminates the residual value method of allocating the selling price. The amended guidance is effective prospectively for all revenue arrangements entered into or materially modified in fiscal years beginning after June 15, 2010. The amendment is not expected to have a material effect on the Partnership's condensed consolidated financial statements.

        In February 2010, the FASB amended the embedded derivative and hedging guidance. The amended guidance modified the requirements for determining whether an embedded derivative is clearly and closely related to the host contract. The amended embedded derivative guidance was

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

2. Recent Accounting Pronouncements (Continued)


effective for the Partnership on January 1, 2010. The amended guidance had no effect on the Partnership's condensed consolidated financial statements.

        In March 2010, the FASB amended the exception for embedded credit derivatives in the derivatives and hedging guidance. The amended guidance clarified which types of embedded credit derivative features are required to be analyzed for potential bifurcation. The amended guidance is effective for the Partnership on July 1, 2010. The Partnership is currently evaluating the effect of the amended guidance on the Partnership's condensed consolidated financial statements.

3. Variable Interest Entities

    MarkWest Liberty Midstream

        MarkWest Liberty Midstream operates in the natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. Equity interests in the entity are owned 60% by the Partnership and 40% by M&R MWE Liberty, LLC ("M&R"), an affiliate of The Energy & Minerals Group and its affiliated funds, which prior to March 15, 2010 was named Midstream & Resources Funds, until December 31, 2010. Effective January 1, 2011 the equity interests in the entity will be owned 51% and 49% by the Partnership and M&R, respectively. A wholly-owned subsidiary of the Partnership serves as the operator and provides field operating and general and administrative services for a fee, a portion of which is fixed. The Partnership's Liberty segment includes the results of operations of MarkWest Liberty Midstream (see Note 13).

        The Partnership and M&R will jointly fund the capital requirements of MarkWest Liberty Midstream at agreed upon levels until the Partnership's contributed capital is proportionate to its eventual 51% ownership interest (the "Equalization Date"), which is expected to occur on or before December 31, 2012. The Partnership is required to reinvest all cash distributions from MarkWest Liberty Midstream until the Equalization Date has occurred. During 2010, M&R will contribute at least $150.0 million to MarkWest Liberty Midstream and the Partnership will fund all capital expenditures in excess of M&R's contributions. MarkWest Liberty Midstream's capital plan for 2011 and 2012 has not been finalized and the exact timing of the members' contributions is currently uncertain. If the Equalization Date has not occurred by the end of 2012, M&R may require the Partnership to contribute the amount of the shortfall at December 31, 2012, or may allow the Partnership to continue to fund up to 100% of MarkWest Liberty Midstream's capital expenditures until its total contributed capital is proportionate to its ownership interest. Following the Equalization Date, M&R will have pre-emptive rights to maintain its ownership interest in MarkWest Liberty Midstream in a range of between 45% and 49% or have its ownership interest diluted to the extent that it elects not to fund its proportionate share.

        As of March 31, 2010, the capital contributed to MarkWest Liberty Midstream is disproportionate to each member's respective ownership interest. Under the terms of the joint venture agreement, M&R received a special $2.3 million non-cash allocation of net income from MarkWest Liberty Midstream during the first quarter of 2010 because the capital M&R contributed exceeded its ownership interest by $89.3 million. The non-cash allocation is recorded in Net (income) loss attributable to non-controlling interest.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Variable Interest Entities (Continued)

    MarkWest Pioneer

        MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that was placed in service in July 2009. The Arkoma Connector Pipeline interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline and is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity. A wholly-owned subsidiary of the Partnership serves as the operator and provides field operating and general and administrative services for fixed fees. The Partnership's Southwest segment includes the results of operations of MarkWest Pioneer (see Note 13).

        Equity interests in the entity are shared equally by the members. The Partnership was obligated to fund all capital expenditures necessary to complete construction of the Arkoma Connector Pipeline in excess of $125.0 million. As of March 31, 2010, the carrying value of the Partnership's ownership interest exceeds its stated ownership interest in MarkWest Pioneer by approximately $2.0 million. The difference between the carrying value of the Partnership's ownership interest and its stated ownership interest is amortized based upon the respective useful lives of the assets to which the difference relates.

    Significant Judgments Regarding VIEs

        The Partnership has determined that MarkWest Liberty Midstream and MarkWest Pioneer are both VIEs primarily due to the Partnership's disproportionate economic interests as compared to its voting interests in each entity. The Partnership has made capital contributions to both entities that differ from its stated ownership interests. Additionally, MarkWest Liberty Midstream has insufficient equity at risk, as evidenced by the additional capital funding requirements discussed above.

        Although voting interests are shared equally between the respective members in both MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership has concluded that it is the primary beneficiary of both entities based on its affiliate's role as the operator. The Partnership believes that its role as the operator along with its equity interests give it the power to direct the activities that most significantly affect the economic performance of each VIE.

    Financial Statement Impact of VIEs

        As the primary beneficiary of MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership consolidates the entities and recognizes non-controlling interests. The following tables show

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Variable Interest Entities (Continued)

the assets and liabilities attributable to VIEs as of March 31, 2010 and December 31, 2009 (in thousands):

 
  As of March 31, 2010  
 
  MarkWest Liberty
Midstream
  MarkWest
Pioneer
  Total  

ASSETS

                   
 

Cash and cash equivalents

  $ 52,038   $ 2,906   $ 54,944  
 

Accounts receivable

    26,556     1,289     27,845  
 

Inventories

    2,243         2,243  
 

Other current assets

    258     102     360  
 

Property, plant and equipment, net of accumulated depreciation of $12,236 and $4,618, respectively

   
383,278
   
152,177
   
535,455
 
 

Other long-term assets

    300         300  
               
   

Total assets

  $ 464,673   $ 156,474   $ 621,147  
               

LIABILITIES

                   
 

Accounts payable

  $ 6,398   $ 28   $ 6,426  
 

Accrued liabilities

    49,284     915     50,199  
 

Other long-term liabilities

    82     290     372  
               
   

Total liabilities

  $ 55,764   $ 1,233   $ 56,997  
               

 

 
  As of December 31, 2009  
 
  MarkWest Liberty
Midstream
  MarkWest
Pioneer
  Total  

ASSETS

                   
 

Cash and cash equivalents

  $ 18,168   $ 3,774   $ 21,942  
 

Accounts receivable

    20,753     1,280     22,033  
 

Inventories

    3,343         3,343  
 

Other current assets

    225     102     327  
 

Property, plant and equipment, net of accumulated depreciation of $8,273 and $3,051, respectively

   
330,116
   
153,478
   
483,594
 
 

Other long-term assets

    314         314  
               
   

Total assets

  $ 372,919   $ 158,634   $ 531,553  
               

LIABILITIES

                   
 

Accounts payable

  $ 2,713   $ 32   $ 2,745  
 

Accrued liabilities

    43,136     1,479     44,615  
 

Other long-term liabilities

    80     285     365  
               
   

Total liabilities

  $ 45,929   $ 1,796   $ 47,725  
               

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Variable Interest Entities (Continued)

        The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including collateral for its secured debt (see Note 7 and Note 14). The liabilities of the VIEs do not represent additional claims against the Partnership's general assets. The cash flow information for MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the cash flow information of the Partnership's non-guarantor subsidiaries (see Note 14). The Partnership's maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its subsidiary's compensation for the performance of those services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the three months ended March 31, 2010 and 2009.

        The following table shows the net income (loss) attributable to the Partnership and transfers to the non-controlling interest for the three months ended March 31, 2010 and 2009 (in thousands).

 
  Three Months Ended
March 31,
 
 
  2010   2009  

Net income (loss) attributable to the Partnership

  $ 21,510   $ (29,649 )
 

Transfers to the non-controlling interest:

             
   

Decrease in Partners' Capital for transaction costs related to sale of 40% interest in Liberty Midstream

        (5,464 )
           

Net income (loss) attributable to the Partnership and transfers to the non-controlling interest

  $ 21,510   $ (35,113 )
           

4. Derivative Financial Instruments

    Commodity Contracts

        The Partnership's primary risk management objective is to reduce downside volatility in its cash flows arising from changes in commodity prices related to future sales or purchases of natural gas, NGLs and crude oil. Swaps, options and fixed price forward contracts may allow the Partnership to reduce downside volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership's sales or purchases of physical product. While management largely expects realized derivative gains and losses to be offset by increases or decreases in the value of physical sales and purchases, the Partnership will experience volatility in reported earnings due to the recording of unrealized gains and losses on derivative positions that will have no offset. The Partnership's commodity derivative instruments are recorded at fair value in the Condensed Consolidated Balance Sheets. Accordingly, the volatility in any given period related to unrealized gains or losses reported in the Condensed Consolidated Statements of Operations can be significant to the overall financial results of the Partnership; however, management generally expects those gains and losses to be offset when they become realized. The Partnership does not have any trading derivative financial instruments.

        To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. To

10


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)


mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas. As a result of these transactions, the Partnership has mitigated a significant portion of its expected commodity price risk with agreements expiring at various times through the fourth quarter of 2012. The Partnership has a committee comprised of the senior management team that oversees risk management activity and continually monitors the risk management program and expects to continue to adjust its derivative positions as conditions warrant.

        To manage its commodity price risk, the Partnership utilizes a combination of swaps, options and fixed price forward contracts available on the OTC market. The Partnership enters into OTC derivatives with financial institutions and other energy company counterparties. Management conducts a standard credit review on counterparties and has agreements containing collateral requirements when deemed necessary. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

        The use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) physical sales volumes are less than expected or (iii) OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that the Partnership engages in derivative activities, it may be prevented from realizing the benefits of favorable price changes in the physical market; however, it may be insulated against unfavorable changes in such prices.

        The Partnership's amended credit agreement (the "Partnership Credit Agreement") limits its ability to enter into financial derivative transactions with parties that require margin calls and prevents members of the participating bank group from requiring margin calls. As of March 31, 2010 approximately 5% of the Partnership's financial derivative positions, measured volumetrically, are with non-bank group counterparties and are subject to margin deposit requirements under OTC agreements that it meets with letters of credit, if necessary. In the unlikely event that the Partnership was unable to meet these margin calls with letters of credit, it would be forced to terminate the corresponding contracts.

    Embedded Derivative in Debt Contract

        The senior notes issued in 2009 contain two contingent written put options. The written put options are considered embedded derivatives and are not considered clearly and closely related to the indenture governing the notes. When a hybrid contract contains more than one embedded derivative requiring separate accounting, the embedded derivatives must be aggregated and accounted for as one compound embedded derivative. The initial fair value of the compound embedded derivative in the indenture was recorded as a component of Long-term debt in the Condensed Consolidated Balance Sheets with a corresponding increase in the recorded balance of the original issue discount.

    Interest Rate Contracts

        During the first quarter of 2010, the Partnership terminated all of its outstanding interest rate swap contracts. The financial statement impact is disclosed in the tables below.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

    Financial Statement Impact of Derivative Contracts

        See Note 5 for a description of how the Partnership values its derivative instruments. There were no material changes to its policy regarding the accounting for these instruments as previously disclosed in the Partnership's 2009 Annual Report on Form 10-K. The impact of the Partnership's derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

 
  Asset Derivatives   Liability Derivatives  
Derivative contracts not designated as hedging
instruments and their balance sheet location
  Fair Value at
March 31, 2010
  Fair Value at
December 31, 2009
  Fair Value at
March 31, 2010
  Fair Value at
December 31, 2009
 

Commodity contracts

                         
 

Fair value of derivative instruments—current

  $ 8,002   $ 8,312   $ (63,544 ) $ (60,464 )
 

Fair value of derivative instruments—long-term

    9,968     15,810     (55,103 )   (62,519 )

Interest rate contracts

                         
 

Fair value of derivative instruments—current

        509          

Embedded derivative in debt contract

                         
 

Long-term debt

            (134 )   (190 )
                   
   

Total

  $ 17,970   $ 24,631   $ (118,781 ) $ (123,173 )
                   

12


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

        The impact of the Partnership's derivative instruments on its Condensed Consolidated Statements of Operations is summarized below (in thousands):

 
  Three months ended
March 31,
 
Derivative contracts not designated as hedging instruments
and the location of gain or (loss) recognized in income
  2010   2009  

Revenue: Derivative (loss) gain

             
 

Realized (loss) gain

  $ (13,129 ) $ 61,114  
 

Unrealized gain (loss)

    5,893     (52,810 )
           
   

Total Revenue: derivative (loss) gain

    (7,236 )   8,304  
           

Derivative loss related to purchased product costs

             
 

Realized loss

    (5,438 )   (16,250 )
 

Unrealized loss

    (7,951 )   (13,263 )
           
   

Total derivative loss related to purchased product costs

    (13,389 )   (29,513 )
           

Derivative gain related to facility expenses

             
 

Unrealized gain

    806     371  

Derivative gain related to interest expense

             
 

Realized gain

    2,380      
 

Unrealized loss

    (509 )    
           
   

Total derivative gain related to interest expense

    1,871      
           

Miscellaneous income (expense), net

             
 

Unrealized gain

    56      
           
   

Total loss

  $ (17,892 ) $ (20,838 )
           

        At March 31, 2010, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of $7.1 million, net of amortization. For the three months ended March 31, 2010 and 2009, the Realized (loss) gain—revenue includes amortization of premium payments of $0.6 million and $1.2 million, respectively.

        During the first quarter of 2009, the Partnership settled a portion of its derivative positions covering 2009, 2010, and 2011 for $15.2 million of net realized gains. The settlement was completed prior to the contractual settlement to improve liquidity and to mitigate credit risk with certain counterparties, and as such did not represent trading activity. The settlement was recorded as a $26.5 million realized gain in Realized (loss) gain—revenue and an $11.3 million realized loss included in Derivative loss related to purchased product costs in the accompanying Condensed Consolidated Statements of Operations.

    Credit Risk Contingent Feature

        The Partnership has a contractual arrangement with one non-bank group counterparty that contains a credit risk contingent feature. The Partnership has OTC swap and put positions with this counterparty. This arrangement contains provisions that if the Partnership's credit rating for its

13


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

long-term senior unsecured debt, as announced by Moody's Investors Service, Inc. and Standard & Poor's Corporation were to decline below B3 or B-, respectively, the Partnership would be required to post additional collateral in the amount of 15% of all outstanding transactions if the contract value of all outstanding transactions was in a net liability position. The Partnership has a standard master netting arrangement with this counterparty. As of March 31, 2010 the Partnership has a net liability position of $1.1 million with this counterparty. The Partnership has posted additional collateral with the counterparty through a letter of credit due to a restriction in the Partnership Credit Agreement which does not allow cash collateral.

    Outstanding Derivative Contracts

        The following tables provide information on the volume of the Partnership's derivative activity for positions related to long liquids and keep-whole price risk at March 31, 2010, including the weighted average prices ("WAVG"):

WTI Crude Collars
  Volumes
(Bbl/d)
  WAVG Floor
(Per Bbl)
  WAVG Cap
(Per Bbl)
  Fair Value
(in thousands)
 

2010

    1,297   $ 66.48   $ 74.49   $ (4,033 )

2011

    2,495     70.06     86.95     (4,880 )

2012

    822     60.00     85.87     (2,944 )

 

WTI Crude Puts
  Volumes
(Bbl/d)
  WAVG Floor
(Per Bbl)
  Fair Value
(in thousands)
 

2010

    1,288   $ 80.00   $ 1,525  

2011

    1,818     80.00     5,229  

 

WTI Crude Swaps
  Volumes
(Bbl/d)
  WAVG Price
(Per Bbl)
  Fair Value
(in thousands)
 

2010

    3,290   $ 70.68   $ (12,358 )

2011

    1,570     78.54     (4,166 )

2012

    1,221     78.50     (3,463 )

 

Natural Gas Swaps
  Volumes
(MMBtu/d)
  WAVG Price
(Per MMBtu)
  Fair Value
(in thousands)
 

2010

    5,186   $ 5.68   $ (2,138 )

 

IsoButane Swaps
  Volumes
(Gal/d)
  WAVG Price
(Per Gal)
  Fair Value
(in thousands)
 

2010

    5,525   $ 1.35   $ (271 )

 

Natural Gasoline Swaps
  Volumes
(Gal/d)
  WAVG Price
(Per Gal)
  Fair Value
(in thousands)
 

2010

    10,898   $ 1.66   $ (582 )

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Table of Contents


MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

 

Normal Butane Swaps
  Volumes
(Gal/d)
  WAVG Price
(Per Gal)
  Fair Value
(in thousands)
 

2010

    8,983   $ 1.29   $ (215 )

 

Propane Swaps
  Volumes
(Gal/d)
  WAVG Price
(Per Gal)
  Fair Value
(in thousands)
 

2010

    27,374   $ 1.04   $ (578 )

        The following tables provide information on the volume of the Partnership's taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk at March 31, 2010, including the WAVG:

WTI Crude Collars
  Volumes
(Bbl/d)
  WAVG Floor
(Per Bbl)
  WAVG Cap
(Per Bbl)
  Fair Value
(in thousands)
 

2012

    648   $ 70.00   $ 91.85   $ (1,158 )

 

WTI Crude Swaps
  Volumes
(Bbl/d)
  WAVG Price
(Per Bbl)
  Fair Value
(in thousands)
 

2010

    2,782   $ 74.47   $ (7,761 )

2011

    3,150     87.27     1,267  

2012 (Jan)

    2,142     91.50     306  

 

Natural Gas Swaps
  Volumes
(MMBtu/d)
  WAVG Price
(Per MMBtu)
  Fair Value
(in thousands)
 

2010

    9,992   $ 9.39   $ (13,754 )

2011

    15,429     8.79     (18,056 )

2012

    4,225     7.08     (1,786 )

    Embedded Derivatives in Commodity Contracts

        The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The primary term of the commodity contract, a component of a broader regional arrangement, expired on December 31, 2009 but the producer exercised its right to extend the processing agreement and the commodity contract through the first quarter of 2015. The fair value of the commodity contract is marked based on an index price through Derivative loss related to purchased product costs. As of March 31, 2010, the estimated fair value of this contract was a liability of $31.4 million.

        The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at one of its plant locations. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of March 31, 2010, the estimated fair value of this contract was an asset of $0.6 million.

15


Table of Contents


MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value

        Fair value measurements and disclosures relate primarily to the Partnership's derivative instruments discussed in Note 4. The derivative contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates are an observable input for the measurement of all derivative contracts. The measurements for all commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil prices; Columbia Appalachia, Henry Hub and Houston Ship Channel natural gas prices; Mont Belvieu and Conway NGL prices; and ERCOT electricity prices. Level 2 instruments include crude oil and natural gas swap contracts; the valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include crude oil options, all NGL transactions, embedded derivatives in commodity contracts and the embedded put options. The significant unobservable inputs for crude oil options, NGL transactions and embedded derivatives in commodity contracts include option volatilities and commodity prices interpolated and extrapolated due to inactive markets. The significant unobservable inputs for the embedded put options are option volatilities and management's assumptions about the probability of specific events occurring in the future.

        The methods and assumptions described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date.

        The following table presents the derivative instruments carried at fair value as of March 31, 2010 and December 31, 2009 (in thousands):

As of March 31, 2010
  Assets   Liabilities  

Significant other observable inputs (Level 2)

             
 

Commodity contracts

  $ 8,010   $ (69,919 )

Significant unobservable inputs (Level 3)

             
 

Commodity contracts

    9,413     (17,320 )
 

Embedded derivatives in commodity contracts

    547     (31,408 )
 

Embedded derivative in debt contract

        (134 )
           

Total carrying value in Condensed Consolidated Balance Sheet

  $ 17,970   $ (118,781 )
           

 

As of December 31, 2009
  Assets   Liabilities  

Significant other observable inputs (Level 2)

             
 

Commodity contracts

  $ 9,920   $ (63,242 )

Significant unobservable inputs (Level 3)

             
 

Commodity contracts

    14,202     (25,542 )
 

Embedded derivatives in commodity contracts

        (34,199 )
 

Interest rate contracts

    509      
 

Embedded derivative in debt contract

        (190 )
           

Total carrying value in Condensed Consolidated Balance Sheet

  $ 24,631   $ (123,173 )
           

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Table of Contents


MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value (Continued)

Changes in Level 3 Fair Value Measurements

        The table below includes a rollforward of the balance sheet amounts for the three months ended March 31, 2010 and 2009 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

 
  Three Months Ended  
 
  March 31, 2010   March 31, 2009  
 
  Commodity
Derivative
Contracts
(net)
  Embedded
Derivatives in
Commodity
Contracts
(net)
  Interest
Rate
Contracts
  Embedded
Derivative
in Debt
Contract
  Commodity
Derivative
Contracts
(net)
  Embedded
Derivatives in
Commodity
Contracts
(net)
 

Fair value at beginning of period

  $ (11,340 ) $ (34,199 ) $ 509   $ (190 ) $ 72,478   $ (22 )

Total gain or loss (realized and unrealized) included in earnings(1)

    (2,758 )   936     1,871     56     1,430     (2,455 )

Purchases, sales, issuances and settlements (net)

    6,191     2,402     (2,380 )       (19,967 )   208  
                           

Fair value at end of period

  $ (7,907 ) $ (30,861 ) $   $ (134 ) $ 53,941   $ (2,269 )
                           

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at March 31(1)

  $ (3,521 ) $ 3,338   $   $ 56   $ (5,063 ) $ (2,247 )
                           

(1)
Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative (loss) gain related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in purchased product costs and facility expenses. Gains on Embedded Derivatives in Debt Contracts are recorded in Miscellaneous income (expense), net. Gains and losses on Interest Rate Contracts are recorded in Derivative gain related to interest expense.

6. Inventories

        Inventories consist of the following (in thousands):

 
  March 31, 2010   December 31, 2009  

Natural gas and natural gas liquids

  $ 13,095   $ 20,939  

Spare parts

    6,831     8,136  
           
 

Total inventories

  $ 19,926   $ 29,075  
           

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Table of Contents


MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

7. Long-Term Debt

        Debt is summarized below (in thousands):

 
  March 31, 2010   December 31, 2009  

Credit Facility

             
 

Revolving credit facility, 5.25% interest at March 31, 2010 and December 31, 2009, due February 2012

  $ 53,000   $ 59,300  

Senior Notes(1)

             
 

Senior Notes, 6.875% interest, net of discount of $7,685 and $8,089, respectively, issued October 2004 and due November 2014

    217,315     216,911  
 

Senior Notes, 6.875% interest, net of discount of $28,392 and $29,515, respectively, issued May 2009 and due November 2014(2)

    121,742     120,674  
 

Senior Notes, 8.5% interest, net of discount of $732 and $762, respectively, issued July 2006 and due July 2016

    274,268     274,238  
 

Senior Notes, 8.75% interest, net of discount of $1,019 and $1,051, respectively, issued April and May 2008 and due April 2018

    498,981     498,949  
           
   

Total long-term debt

  $ 1,165,306   $ 1,170,072  
           

(1)
The estimated aggregate fair value of the Senior Notes was approximately $1,158.2 million and $1,152.9 million as of March 31, 2010 and December 31, 2009, respectively, based on quoted market prices.

(2)
Includes fair value of written put options of approximately $0.1 million (see Note 4).

    Credit Facility

        Under the provisions of the Partnership Credit Agreement, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The credit facility is guaranteed and collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries. As of March 31, 2010, the Partnership had $53.0 million of borrowings outstanding and $37.5 million of letters of credit outstanding under the revolving credit facility, leaving approximately $345.1 million available for borrowing.

8. Equity

    Distributions of Available Cash

Quarter Ended
  Distribution Per
Common Unit
  Declaration Date   Ex-Dividend Date   Record Date   Payment Date  

March 31, 2010

  $ 0.64     April 22, 2010     April 29, 2010     May 3, 2010     May 14, 2010  

December 31, 2009

  $ 0.64     January 26, 2010     February 3, 2010     February 5, 2010     February 12, 2010  

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

9. Commitments and Contingencies

    Legal

        The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. However, the Partnership cannot assure that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for property loss or business interruption to the Partnership, or for third-party claims of personal and property damage, or that the coverages or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the condensed consolidated financial statements.

        In June 2006, the Office of Pipeline Safety ("OPS") issued a Notice of Probable Violation and Proposed Civil Penalty ("NOPV") (CPF No. 2-2006-5001) to both MarkWest Hydrocarbon and Equitable Production Company ("Equitable"). The NOPV is associated with the pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel, Kentucky on an NGL pipeline owned by Equitable and leased and operated by a subsidiary, MarkWest Energy Appalachia, L.L.C. The NOPV sets forth six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1.1 million. An administrative hearing on the matter, previously set for the last week of March 2007, was postponed to allow the administrative record to be produced and to allow OPS an opportunity to respond to MarkWest's and Equitable's motions to dismiss count one of the NOPV, which involves $0.8 million of the $1.1 million proposed penalty. This count arises out of alleged activity in 1982 and 1987, which predates MarkWest's leasing and operation of the pipeline. MarkWest believes it has viable and mitigating defenses to the remaining counts and will vigorously defend all applicable assertions of violations. The administrative hearing request was withdrawn by MarkWest and Equitable in October 2009, and the parties are waiting for initial resolution on the briefs, exhibits and other documents filed or submitted by the parties in the matter.

        MarkWest Javelina Company, L.L.C. is a party to an action styled Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005, which sets forth claims for wrongful death, personal injury or property damage, and nuisance type claims, allegedly incurred as a result of operations and emissions from MarkWest Javelina's gas processing plant and from various petroleum, petrochemical and metal processing and refining operations located in the area, which were also named as defendants in the action. The action has been and is being vigorously defended, and management does not believe that this action will have a material adverse impact on the Partnership's financial position or results of operations.

        In the ordinary course of business, the Partnership is a party to various other legal and regulatory actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operations.

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Table of Contents


MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

10. Incentive Compensation Plans

Compensation Expense

        Total compensation expense recorded for share-based pay arrangements is as follows (in thousands):

 
  Three months ended
March 31,
 
 
  2010   2009  

Phantom units

  $ 6,285   $ 2,703  

Distribution equivalent rights

    311     338  
           

Total compensation expense

  $ 6,596   $ 3,041  
           

        As of March 31, 2010, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP and 2006 Hydrocarbon Plan was approximately $16.1 million, with a weighted-average remaining vesting period of approximately 1.1 years. Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP was approximately $0.3 million, with a weighted-average remaining vesting period of approximately 0.8 years. The actual compensation expense recognized for awards under the 2002 LTIP may differ as they qualify as liability awards, which are affected by changes in the fair value.

        As part of a net settlement option, employees may elect to surrender a certain number of phantom units upon vesting, and in exchange, the Partnership will assume the income tax withholding obligations related to the vesting. During the three months ended March 31, 2010 and 2009, the Partnership was required to pay approximately $3.7 million and $1.2 million, respectively, for income tax withholdings related to the vesting of phantom unit awards. Other than the amounts paid related to the net settlement option, there were no cash settlements and the Partnership received no proceeds for issuing phantom units during the three months ended March 31, 2010 and 2009.

2008 LTIP and 2006 Hydrocarbon Plan

        The following is a summary of phantom unit activity under the 2008 LTIP and 2006 Hydrocarbon Plan:

 
  Number of Units   Weighted-average Grant-date
Fair Value
 

Unvested at December 31, 2009(1)

    977,241   $ 22.00  
 

Granted(2)

    272,188     29.27  
 

Vested(2)

    (355,837 )   26.71  
 

Forfeited

    (5,778 )   19.13  
             

Unvested at March 31, 2010(1)

    887,814     22.36  
             

(1)
Includes 437,100 performance units granted to senior executives and other key employees that contain performance vesting criteria. Compensation expense recognized for performance units expected to vest was zero and $0.3 million for the three months ended March 31, 2010 and 2009, respectively.

20


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

10. Incentive Compensation Plans (Continued)

(2)
In January 2010, the General Partner's board of directors granted 166,000 unrestricted units to senior executives and other key employees under the 2008 LTIP. The unrestricted units vested immediately and the Partnership recognized approximately $4.8 million of expense related to these units.

 
  Three months ended
March 31,
 
 
  2010   2009  
 
  (in thousands)
 

Total grant-date fair value of phantom units granted during the period

  $ 7,968   $ 3,649  

Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period

  $ 9,505   $ 9,064  

2002 LTIP

        The following is a summary of phantom unit activity under the 2002 LTIP:

 
  Number of Units   Weighted-average Grant-date
Fair Value
 

Unvested at December 31, 2009

    69,555   $ 32.75  
 

Granted

         
 

Vested

    (43,308 )   32.06  
 

Forfeited

    (256 )   34.00  
             

Unvested at March 31, 2010

    25,991     33.87  
             

 

 
  Three months ended
March 31,
 
 
  2010   2009  
 
  (in thousands)
 

Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period

  $ 1,255   $ 818  

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

11. Income Taxes

        A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35% to the income (loss) before income tax for the three months ended March 31, 2010 and 2009 is as follows (in thousands):

 
  Three months ended March 31, 2010  
 
  Corporation   Partnership   Eliminations   Consolidated  

Income before provision for income tax

  $ 3,234   $ 27,302   $ (106 ) $ 30,430  
                         

Federal statutory rate

    35 %   0 %   0 %      
                     

Federal income tax at statutory rate

  $ 1,132   $   $   $ 1,132  

Permanent items

    1             1  

State income taxes net of federal benefit

    115     155         270  

Provision on income from Class A units(1)

    3,023             3,023  
                   
 

Provision for income tax

  $ 4,271   $ 155   $   $ 4,426  
                   

Effective tax rate

                      14.54 %

 

 
  Three months ended March 31, 2009  
 
  Corporation   Partnership   Eliminations   Consolidated  

Loss before provision for income tax

  $ (26,817 ) $ (7,661 ) $ (4,529 ) $ (39,007 )
                         

Federal statutory rate

    35 %   0 %   0 %      
                     

Federal income tax at statutory rate

  $ (9,386 ) $   $   $ (9,386 )

Permanent items

    13             13  

State income taxes net of federal benefit

    (658 )   (48 )       (706 )

Provision on income from Class A units(1)

    3             3  

Excess book deduction related to equity compensation

    735     3         738  
                   
 

Provision for income tax

  $ (9,293 ) $ (45 ) $   $ (9,338 )
                   

Effective tax rate

                      23.94 %

(1)
The Corporation and the General Partner of the Partnership own Class A units of the Partnership that were received in the merger. For further discussion, see Item 1. Business in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009.

22


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

12. Earnings (Loss) Per Common Unit

        The following table shows the computation of basic and diluted net income (loss) per common unit for the three months ended March 31, 2010 and 2009, and the weighted-average units used to compute diluted net income (loss) per common unit (in thousands, except per unit data):

 
  Three months ended
March 31,
 
 
  2010   2009  

Net income (loss) attributable to the Partnership

  $ 21,510   $ (29,649 )

Less: Income allocable to phantom units

    277     390  
           

Income (loss) available for common unitholders

  $ 21,233   $ (30,039 )
           

Weighted average common units outstanding—basic

    66,453     56,806  
           

Weighted average common units outstanding—diluted

    66,453     56,806  
           

Net income (loss) attributable to the Partnership's common unitholders per common unit

             
 

Basic

  $ 0.32   $ (0.53 )
 

Diluted

  $ 0.32   $ (0.53 )

13. Segment Information

        The Partnership prepares segment information in accordance with GAAP. Certain items below Income (loss) from operations in the accompanying Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any unrealized gains (losses) from derivative instruments are not allocated to individual segments. Management does not consider these items allocable to or controllable by any individual segment and therefore excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.

23


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information (Continued)

        The tables below present information about operating income and capital expenditures for the reported segments for the three months ended March 31, 2010 and 2009 (in thousands).

Three months ended March 31, 2010:
  Southwest   Northeast   Liberty   Gulf Coast   Total  

Revenue

  $ 164,964   $ 111,848   $ 19,010   $ 19,793   $ 315,615  

Operating expenses:

                               
 

Purchased product costs

    74,625     67,087     2,584         144,296  
 

Facility expenses

    20,489     4,225     7,313     5,695     37,722  
                       

Total operating expenses before items not allocated to segments

    95,114     71,312     9,897     5,695     182,018  
 

Portion of operating income attributable to non-controlling interests

   
1,500
   
   
3,637
   
   
5,137
 
                       

Operating income before items not allocated to segments

  $ 68,350   $ 40,536   $ 5,476   $ 14,098   $ 128,460  
                       

Capital expenditures

  $ 40,133   $ 591   $ 51,217   $ 2,865   $ 94,806  

Capital expenditures not allocated to segments

                            516  
                               
   

Total capital expenditures

                          $ 95,322  
                               

 

Three months ended March 31, 2009:
  Southwest   Northeast   Liberty   Gulf Coast   Total  

Revenue

  $ 104,606   $ 61,592   $ 6,656   $ 10,513   $ 183,367  

Operating expenses:

                               
 

Purchased product costs

    50,534     50,954     826         102,314  
 

Facility expenses

    18,125     5,165     2,539     5,271     31,100  
                       

Total operating expenses before items not allocated to segments

    68,659     56,119     3,365     5,271     133,414  
 

Portion of operating income attributable to non-controlling interests

   
28
   
   
280
   
   
308
 
                       

Operating income before items not allocated to segments

  $ 35,919   $ 5,473   $ 3,011   $ 5,242   $ 49,645  
                       

Capital expenditures

  $ 84,429   $ 13,224   $ 50,290   $ 20,877   $ 168,820  

Capital expenditures not allocated to segments

                            122  
                               
   

Total capital expenditures

                          $ 168,942  
                               

24


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information (Continued)

        The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income (loss) before provision for income tax for the three months ended March 31, 2010 and 2009 (in thousands).

 
  Three months ended
March 31,
 
 
  2010   2009  

Total segment revenue

  $ 315,615   $ 183,367  
 

Derivative (loss) gain not allocated to segments

    (7,236 )   8,304  
           
   

Total revenue

  $ 308,379   $ 191,671  
           

Operating income before items not allocated to segments

  $ 128,460   $ 49,645  
 

Portion of operating income attributable to non-controlling interests

    5,137     308  
 

Derivative loss not allocated to segments

    (19,819 )   (20,838 )
 

Compensation expense included in facility expenses not allocated to segments

    (722 )   (344 )
 

Facility expenses adjustment

    539      
 

Selling, general and administrative expenses

    (21,508 )   (15,927 )
 

Depreciation

    (28,187 )   (20,943 )
 

Amortization of intangible assets

    (10,193 )   (10,233 )
 

Gain (loss) on disposal of property, plant and equipment

    9     (729 )
 

Accretion of asset retirement obligations

    (143 )   (47 )
           
   

Income (loss) from operations

    53,573     (19,108 )
 

Loss from unconsolidated affiliates

   
(68

)
 
(105

)
 

Interest income

    386     41  
 

Interest expense

    (23,782 )   (17,782 )
 

Amortization of deferred financing costs and discount (a component of interest expense)

    (2,612 )   (1,391 )
 

Derivative gain related to interest expense

    1,871      
 

Miscellaneous income (expense), net

    1,062     (662 )
           
   

Income (loss) before provision for income tax

  $ 30,430   $ (39,007 )
           

25


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information (Continued)

        The tables below present information about segment assets as of March 31, 2010 and December 31, 2009 (in thousands):

As of March 31, 2010:
  Southwest   Northeast   Liberty   Gulf Coast   Total  

Total segment assets

  $ 1,652,732   $ 228,021   $ 464,673   $ 590,000   $ 2,935,426  

Assets not allocated to segments:

                               
 

Certain cash and cash equivalents

                            48,145  
 

Fair value of derivatives

                            17,970  
 

Investment in unconsolidated affiliate

                            29,565  
 

Other(1)

                            30,024  
                               

Total assets

                          $ 3,061,130  
                               

(1)
Includes corporate fixed assets, receivables, deferred financing costs and other corporate assets not allocated to segments.

As of December 31, 2009:
  Southwest   Northeast   Liberty   Gulf Coast   Total  

Total segment assets

  $ 1,637,749   $ 249,804   $ 373,127   $ 587,830   $ 2,848,510  

Assets not allocated to segments:

                               
 

Certain cash and cash equivalents

                            73,184  
 

Fair value of derivatives

                            24,631  
 

Investment in unconsolidated affiliate

                            29,633  
 

Other(1)

                            38,779  
                               

Total assets

                          $ 3,014,737  
                               

(1)
Includes corporate fixed assets, deferred financing costs, income tax receivable and other corporate assets not allocated to segments.

14. Supplemental Condensed Consolidating Financial Information

        MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of March 31, 2010, the Partnership's obligations under the outstanding Senior Notes (see Note 7) were fully and unconditionally guaranteed, jointly and severally, by all of its wholly-owned subsidiaries. MarkWest Liberty Midstream and MarkWest Pioneer, together with certain of the Partnership's other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in aggregate. 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. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows and financial position of the co-issuer of the Senior Notes, MarkWest Energy Finance Corporation, are minor and therefore have been included with the Parent's financial information. Condensed consolidating financial information for MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of March 31, 2010

26


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)


and December 31, 2009 and for the three months ended March 31, 2010 and 2009 is as follows (in thousands):

Condensed Consolidating Balance Sheets

 
  As of March 31, 2010  
 
  Parent   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

ASSETS

                               

Current assets:

                               
 

Cash and cash equivalents

  $   $ 48,739   $ 56,436   $   $ 105,175  
 

Receivables and other current assets

    1,378     151,846     30,745         183,969  
 

Intercompany receivables

    1,503,076     1,342         (1,504,418 )    
 

Fair value of derivative instruments

        8,002             8,002  
                       
   

Total current assets

    1,504,454     209,929     87,181     (1,504,418 )   297,146  

Total property, plant and equipment, net

   
3,214
   
1,514,211
   
536,638
   
(6,393

)
 
2,047,670
 

Other long-term assets:

                               
 

Investment in unconsolidated affiliate

        29,565             29,565  
 

Investment in consolidated affiliates

    581,187     237,997         (819,184 )    
 

Intangibles, net of accumulated amortization

        643,613     605         644,218  
 

Fair value of derivative instruments

        9,968             9,968  
 

Intercompany notes receivable

    188,910             (188,910 )    
 

Other long-term assets

    19,501     12,762     300         32,563  
                       
   

Total assets

  $ 2,297,266   $ 2,658,045   $ 624,724   $ (2,518,905 ) $ 3,061,130  
                       

LIABILITIES AND EQUITY

                               

Current liabilities:

                               
 

Intercompany payables

  $   $ 1,503,007   $ 1,411   $ (1,504,418 ) $  
 

Fair value of derivative instruments

        63,544             63,544  
 

Other current liabilities

    40,603     154,487     56,739         251,829  
                       
   

Total current liabilities

    40,603     1,721,038     58,150     (1,504,418 )   315,373  

Deferred income taxes

   
2,448
   
7,214
   
   
   
9,662
 

Intercompany notes payable

        188,910         (188,910 )    

Fair value of derivative instruments

        55,103             55,103  

Long-term debt, net of discounts

    1,165,306                 1,165,306  

Other long-term liabilities

    3,499     104,593     394         108,486  

Equity:

                               
 

MarkWest Energy Partners, L.P. partners' capital

    1,085,410     581,187     566,180     (1,153,760 )   1,079,017  
 

Non-controlling interest in consolidated subsidiaries

   
   
   
   
328,183
   
328,183
 
                       
   

Total equity

    1,085,410     581,187     566,180     (825,577 )   1,407,200  
                       
   

Total liabilities and equity

  $ 2,297,266   $ 2,658,045   $ 624,724   $ (2,518,905 ) $ 3,061,130  
                       

27


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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

 

 
  As of December 31, 2009  
 
  Parent   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

ASSETS

                               

Current assets:

                               
 

Cash and cash equivalents

  $   $ 74,448   $ 23,304   $   $ 97,752  
 

Receivables and other current assets

    870     165,421     26,655         192,946  
 

Intercompany receivables

    1,543,169     2,091     88     (1,545,348 )    
 

Fair value of derivative instruments

    246     8,575             8,821  
                       
   

Total current assets

    1,544,285     250,535     50,047     (1,545,348 )   299,519  

Total property, plant and equipment, net

   
3,307
   
1,499,233
   
484,788
   
(5,684

)
 
1,981,644
 

Other long-term assets:

                               
 

Investment in unconsolidated affiliate

        29,633             29,633  
 

Investment in consolidated affiliates

    529,846     203,895         (733,741 )    
 

Intangibles, net of accumulated amortization

        653,797     614         654,411  
 

Fair value of derivative instruments

        15,810             15,810  
 

Intercompany notes receivable

    210,060             (210,060 )    
 

Other long-term assets

    20,538     13,182             33,720  
                       
   

Total assets

  $ 2,308,036   $ 2,666,085   $ 535,449   $ (2,494,833 ) $ 3,014,737  
                       

LIABILITIES AND EQUITY

                               

Current liabilities:

                               
 

Intercompany payables

  $ 1,195   $ 1,543,257   $ 896   $ (1,545,348 ) $  
 

Fair value of derivative instruments

        60,464             60,464  
 

Other current liabilities

    28,673     149,319     47,527         225,519  
                       
   

Total current liabilities

    29,868     1,753,040     48,423     (1,545,348 )   285,983  

Deferred income taxes

   
2,694
   
8,340
   
   
   
11,034
 

Intercompany notes payable

        210,060         (210,060 )    

Fair value of derivative instruments

        62,519             62,519  

Long-term debt, net of discounts

    1,170,072                 1,170,072  

Other long-term liabilities

    3,064     102,280     392         105,736  

Equity:

                               
 

MarkWest Energy Partners, L.P. partners' capital

    1,102,338     529,846     486,634     (1,022,164 )   1,096,654  
 

Non-controlling interest in consolidated subsidiaries

   
   
   
   
282,739
   
282,739
 
                       
   

Total equity

    1,102,338     529,846     486,634     (739,425 )   1,379,393  
                       
   

Total liabilities and equity

  $ 2,308,036   $ 2,666,085   $ 535,449   $ (2,494,833 ) $ 3,014,737  
                       

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Operations

 
  Three Months Ended March 31, 2010  
 
  Parent   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Total revenue

  $   $ 285,144   $ 23,235   $   $ 308,379  

Operating expenses:

                               
 

Purchased product costs

        155,073     2,612         157,685  
 

Facility expenses

        28,793     8,469     (163 )   37,099  
 

Selling, general and administrative expenses

    11,781     9,635     1,310     (1,218 )   21,508  
 

Depreciation and amortization

    147     32,710     5,597     (74 )   38,380  
 

Other operating expenses

        (155 )   289         134  
                       
   

Total operating expenses

    11,928     226,056     18,277     (1,455 )   254,806  
                       
   

(Loss) income from operations

    (11,928 )   59,088     4,958     1,455     53,573  

Earnings from consolidated affiliates

   
53,853
   
829
   
   
(54,682

)
 
 

Other (expense) income, net

    (19,551 )   (1,793 )   365     (2,164 )   (23,143 )
                       
   

Income before provision for income tax

    22,374     58,124     5,323     (55,391 )   30,430  

Provision for income tax expense

    155     4,271             4,426  
                       
   

Net income

    22,219     53,853     5,323     (55,391 )   26,004  

Net income attributable to non-controlling interest

                (4,494 )   (4,494 )
                       
   

Net income attributable to the Partnership

  $ 22,219   $ 53,853   $ 5,323   $ (59,885 ) $ 21,510  
                       

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

 

 
  Three Months Ended March 31, 2009(1)  
 
  Parent   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Total revenue

  $   $ 188,844   $ 2,827   $   $ 191,671  

Operating expenses:

                               
 

Purchased product costs

        130,989     838         131,827  
 

Facility expenses

        29,655     1,418         31,073  
 

Selling, general and administrative expenses

    11,810     4,397     161     (441 )   15,927  
 

Depreciation and amortization

    143     30,473     560         31,176  
 

Other operating expenses

        776             776  
                       
   

Total operating expenses

    11,953     196,290     2,977     (441 )   210,779  
                       
   

Loss from operations

    (11,953 )   (7,446 )   (150 )   441     (19,108 )

Loss from consolidated affiliates

   
(3,593

)
 
(117

)
 
   
3,710
   
 

Other (expense) income, net

    (13,631 )   (5,323 )   13     (958 )   (19,899 )
                       
   

Loss before provision for income tax

    (29,177 )   (12,886 )   (137 )   3,193     (39,007 )

Provision for income tax benefit

    (45 )   (9,293 )           (9,338 )
                       
   

Net loss

    (29,132 )   (3,593 )   (137 )   3,193     (29,669 )

Net loss attributable to non-controlling interest

                20     20  
                       
   

Net loss attributable to the Partnership

  $ (29,132 ) $ (3,593 ) $ (137 ) $ 3,213   $ (29,649 )
                       

(1)
The condensed consolidating information has been revised to reflect a change in the guarantor structure. MarkWest Pioneer is no longer a guarantor subsidiary due to the Partnership's sale of a 50% equity interest in the entity in May 2009.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

 
  Three Months Ended March 31, 2010  
 
  Parent   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net cash (used in) provided by operating activities

  $ (9,729 ) $ 112,836   $ 12,036   $ (783 ) $ 114,360  

Cash flows from investing activities:

                               
 

Capital expenditures

    (53 )   (42,925 )   (53,127 )   783     (95,322 )
 

Equity investments

    (10,101 )   (34,543 )       44,644      
 

Distributions from consolidated affiliates

    12,710     1,270         (13,980 )    
 

Collection of intercompany notes receivable, net

    21,150             (21,150 )    
 

Proceeds from disposal of property, plant and equipment

        292             292  
                       
   

Net cash flows provided by (used in) investing activities

    23,706     (75,906 )   (53,127 )   10,297     (95,030 )
                       

Cash flows from financing activities:

                               
 

Proceeds from revolving credit facility

    135,604                 135,604  
 

Payments of revolving credit facility

    (141,904 )               (141,904 )
 

Payments of intercompany notes receivable, net

        (21,150 )       21,150      
 

Contributions to wholly-owned subsidiaries, net

        10,101         (10,101 )    
 

Contributions to joint ventures, net

            76,763     (34,543 )   42,220  
 

Payments of SMR liability

        (58 )           (58 )
 

Share-based payment activity

    (3,730 )   97             (3,633 )
 

Payment of distributions

    (42,866 )   (12,710 )   (2,540 )   13,980     (44,136 )
 

Intercompany advances, net

    38,919     (38,919 )            
                       
   

Net cash flows (used in) provided by financing activities

    (13,977 )   (62,639 )   74,223     (9,514 )   (11,907 )
                       

Net (decrease) increase in cash

        (25,709 )   33,132         7,423  

Cash and cash equivalents at beginning of year

        74,448     23,304         97,752  
                       

Cash and cash equivalents at end of period

  $   $ 48,739   $ 56,436   $   $ 105,175  
                       

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

 

 
  Three Months Ended March 31, 2009(1)  
 
  Parent   Guarantor
Subsidiaries
  Non-Guarantor
Subsidiaries
  Consolidating
Adjustments
  Consolidated  

Net cash (used in) provided by operating activities

  $ (11,096 ) $ 97,651   $ 5,782   $ (517 ) $ 91,820  

Cash flows from investing activities:

                               
 

Capital expenditures

    (294 )   (103,180 )   (65,985 )   517     (168,942 )
 

Equity investments

    (14,400 )   (4,984 )       14,400     (4,984 )
 

Change in restricted cash

            (1,125 )       (1,125 )
 

Distributions from consolidated affiliates

        36,267         (36,267 )    
 

Collection of intercompany notes receivable, net

    28,085             (28,085 )    
                       
   

Net cash flows provided by (used in) investing activities

    13,391     (71,897 )   (67,110 )   (49,435 )   (175,051 )
                       

Cash flows from financing activities:

                               
 

Proceeds from revolving credit facility

    234,700                 234,700  
 

Payments of revolving credit facility

    (125,000 )               (125,000 )
 

Payments of intercompany notes receivable, net

        (28,085 )       28,085      
 

Payments for debt issuance costs, deferred financing costs and registration costs

    (4,323 )               (4,323 )
 

Contributions to wholly-owned subsidiaries, net

        14,400         (14,400 )    
 

Contributions to joint ventures, net

    (5,464 )       50,000         44,536  
 

Share-based payment activity

    (1,199 )               (1,199 )
 

Payment of distributions

    (36,803 )       (36,267 )   36,267     (36,803 )
 

Intercompany advances, net

    (64,206 )   16,360     47,698     148      
                       
   

Net cash flows (used in) provided by financing activities

    (2,295 )   2,675     61,431     50,100     111,911  
                       

Net increase in cash

        28,429     103     148     28,680  

Cash and cash equivalents at beginning of year

            3,321         3,321  
                       

Cash and cash equivalents at end of period

  $   $ 28,429   $ 3,424   $ 148   $ 32,001  
                       

(1)
The condensed consolidating information has been revised to reflect a change in the guarantor structure. MarkWest Pioneer is no longer a guarantor subsidiary due to the Partnership's sale of a 50% equity interest in the entity in May 2009.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

15. Supplemental Cash Flow Information

        The following table provides information regarding supplemental cash flow information (in thousands).

 
  Three months ended
March 31,
 
 
  2010   2009  

Supplemental disclosures of cash flow information:

             

Cash paid for interest, net of amounts capitalized

  $ 12,244   $ 8,240  

Cash paid for income taxes

    28     190  

Supplemental schedule of non-cash investing and financing activities:

             

Accrued property, plant and equipment

  $ 59,861   $ 53,445  

Interest capitalized on construction in progress

    2,557     4,893  

Property, plant and equipment asset retirement obligation

    727     321  

Issuance of common units for vesting of share-based payment awards

    7,030     8,683  

16. Subsequent Events

        On April 6, 2010, the Partnership completed a public offering of approximately 4.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option, at a price of $30.43 per common unit. Net proceeds of approximately $142.0 million will be used to partially fund the Partnership's ongoing capital expenditure program and to repay borrowings under the revolving credit facility.

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

        Management's Discussion and Analysis ("MD&A") contains statements that are forward-looking and should be read in conjunction with our condensed consolidated financial statements and accompanying notes included elsewhere in this report and our December 31, 2009 Annual Report on Form 10-K. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors.

Overview

        We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. We have extensive natural gas gathering, processing and transmission operations in the southwest, Gulf Coast and northeast regions of the United States, including the Marcellus Shale, and are the largest natural gas processor in the Appalachian region.

    Significant Financial and Other Highlights

        Significant financial and other highlights for the three months ended March 31, 2010 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

    Total segment operating income before items not allocated to segments increased approximately $78.8 million, or 159%, for the three months ended March 31, 2010 compared to the same period in 2009. The increase is due primarily to higher NGL and natural gas prices in 2010, expanding operations in our Liberty segment and increased volumes from a large producer in our Southwest segment. The increase was partially offset by a $61.1 million decrease in net cash received from the settlement of derivative positions.

    During the three months ended March 31, 2010, we received $42.2 million of contributions to MarkWest Liberty Midstream from M&R.

    Net Operating Margin (a non-GAAP financial measure)

        Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure) which is defined as revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss). These charges have been excluded for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our use of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

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        The following is a reconciliation to income (loss) from operations, the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

 
  Three months ended
March 31,
 
 
  2010   2009  

Revenue

  $ 315,615   $ 183,367  

Purchased product costs

    144,296     102,314  
           
 

Net operating margin

    171,319     81,053  

Facility expenses

    37,905     31,444  

Total derivative loss

    19,819     20,838  

Selling, general and administrative expenses

    21,508     15,927  

Depreciation

    28,187     20,943  

Amortization of intangible assets

    10,193     10,233  

(Gain) loss on disposal of property, plant and equipment

    (9 )   729  

Accretion of asset retirement obligations

    143     47  
           
 

Income (loss) from operations

  $ 53,573   $ (19,108 )
           

    Our Contracts

        We generate the majority of our revenue and net operating margin (a non-GAAP measure, see above for discussion and reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL transportation, fractionation, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. See Item 1. BusinessOur Contracts in our 2009 Annual Report on Form 10-K for further discussion of each of these types of arrangements.

        The following table is prepared as if we did not have an active commodity risk management program in place. For further discussion of how we have reduced the downside volatility to the portion of our net operating margin that is not fee-based, see Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements. For the three months ended March 31, 2010, we calculated the following approximate percentages of our revenue and net operating margin from the following types of contracts:

 
  Fee-Based   Percent-of-Proceeds(1)   Percent-of-Index(2)   Keep-Whole(3)   Total  

Revenue

    17 %   39 %   5 %   39 %   100 %

Net operating margin(4)

    31 %   42 %   0 %   27 %   100 %

(1)
Includes condensate sales and other types of arrangements tied to NGL prices.

(2)
Includes arrangements tied to natural gas prices.

(3)
Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.

(4)
We manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment. The calculated percentages for the net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions.

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    Seasonality

        Our business is affected by seasonal fluctuations in commodity prices. Sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment is particularly impacted by seasonality. In the Appalachia area, we store a portion of the propane that is produced in the summer to be sold in the winter months. As a result of our seasonality, we generally expect the sales volumes in our Northeast and Liberty segments to be higher in the first quarter and fourth quarter.

Results of Operations

    Segment Reporting

        We classify our business in four reportable segments: Southwest, Northeast, Liberty and Gulf Coast. We present information in this MD&A by segment. The segment information appearing in Note 13 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting.

    Southwest

    East Texas.  We own a system that consists of natural gas gathering pipelines, centralized compressor stations, a natural gas processing facility and an NGL pipeline. The East Texas system is located in Panola, Harrison and Rusk Counties and services the Carthage Field. Producing formations in Panola County consist of the Cotton Valley, Pettit, Travis Peak and Haynesville formations, which collectively form one of the largest natural gas producing regions in the United States. For natural gas that is processed in this segment, we purchase the NGLs from the producers primarily under percent-of-proceeds arrangements, or we transport volumes for a fee.

    Oklahoma.  We own a Foss Lake natural gas gathering system and the Arapaho I and II natural gas processing plants, all located in Roger Mills, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. The majority of the gathered gas ultimately is compressed and delivered to the processing plants. We also own and operate a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Foss Lake processing plants and our Grimes gathering system that is located in Roger Mills and Beckham Counties in western Oklahoma. In addition, we own a natural gas gathering system in the Woodford Shale in the Arkoma Basin of southeast Oklahoma.

      Through our joint venture MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity.

    Other Southwest.  We own a number of natural gas gathering systems in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the natural gas produced from fields adjacent to our gathering systems, including from wells targeting the Haynesville formation. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. In addition, we own four lateral pipelines in Texas and New Mexico.

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    Northeast

    Appalachia.  We are the largest processor of natural gas in the Appalachian Basin, with fully integrated processing, fractionation, storage and marketing operations. The Appalachian Basin is a large natural gas producing region characterized by long-lived reserves and modest decline rates. Our Appalachian assets include the Kenova, Boldman, Cobb and Kermit natural gas processing plants, an NGL pipeline, the Siloam NGL fractionation plant and two caverns for storing propane.

    Michigan.  We own and operate a FERC-regulated crude oil pipeline in Michigan providing transportation service for six shippers.

    Liberty

    Marcellus Shale.  We operate natural gas gathering systems and processing facilities located primarily in western Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. We have a 35 MMcf/d cryogenic plant and a 120 MMcf/d cryogenic plant at our Houston, Pennsylvania processing complex and plan to complete the installation of a 200 MMcf/d cryogenic plant in the first half of 2011. We plan to complete the installation of a 120 MMcf/d cryogenic plant at our Majorsville site in the third quarter of 2010 and expect to increase the cryogenic processing capacity to approximately 270 MMcf/d in the third quarter of 2011. We also plan to complete a 60,000 Bbl/d fractionation facility at our Houston complex in the first half of 2011. We expect the total planned capacity of 625 MMcf/d to be supported by long-term agreements with our producer customers. We have also completed construction of an interconnect with a key interstate NGL pipeline providing a market outlet for the propane produced at our Liberty facilities.

    Gulf Coast

    Javelina.  We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries operated by three different refinery customers. We have a hydrogen supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the hydrogen processed by the steam methane reformer ("SMR") that is owned and operated by a third party. The hydrogen received under this agreement will be sold to a refinery customer pursuant to a corresponding long-term agreement.

        The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the three months ended March 31, 2010:

 
  Southwest   Northeast   Liberty   Gulf Coast   Total  

Revenue

    52 %   36 %   6 %   6 %   100 %

Net operating margin

    53 %   26 %   10 %   11 %   100 %

    Equity Investment in Unconsolidated Affiliate

        We own a 40% non-operating membership interest in Centrahoma Processing LLC ("Centrahoma"), a joint venture with Antero Midstream Resources Corporation that is accounted for using the equity method. Centrahoma owns certain processing plants in the Arkoma Basin. We have signed agreements to dedicate our processing rights in certain acreage in the Woodford Shale to Centrahoma through March 1, 2018. The financial results for Centrahoma are included in Earnings from unconsolidated affiliates and are not included in our segment results.

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Three months ended March 31, 2010 compared to three months ended March 31, 2009

        Items below Income (loss) from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any unrealized gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests. The tables below present information about operating income for the reported segments for the three months ended March 31, 2010 and 2009.

Southwest

 
  Three months ended
March 31,
   
   
 
 
  2010   2009   $ Change   % Change  
 
  (in thousands)
   
 

Revenue

  $ 164,964   $ 104,606   $ 60,358     58 %

Operating expenses:

                         
 

Purchased product costs

    74,625     50,534     24,091     48 %
 

Facility expenses

    20,489     18,125     2,364     13 %
                     

Total operating expenses before items not allocated to segments

    95,114     68,659     26,455     39 %
                     

Portion of operating income attributable to non-controlling interests

    1,500     28     1,472     5,257 %
                     

Operating income before items not allocated to segments

  $ 68,350   $ 35,919   $ 32,431     90 %
                     

        Revenue.    Revenue increased primarily due to higher commodity prices. Revenue from NGL, natural gas and condensate sales increased approximately $53.6 million across the segment. An increase in volumes from a large producer in our Woodford Shale operations also contributed to the increase in product sales. Gathering and compression fee revenue also increased $6.3 million due to the higher volumes in the Woodford Shale and Stiles Ranch, and the start of the Arkoma Connector Pipeline in July 2009. The increase in revenue was partially offset by a decrease in volumes in the Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.

        Purchased Product Costs.    Purchased product costs increased primarily due to higher commodity prices and increased volumes in certain areas, which was partially offset by a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.

        Facility Expenses.    Facility expenses increased primarily due to higher repairs and maintenance expense at our East Texas processing facility, the expansion of our operations in Stiles Ranch and the Arkoma Connector Pipeline.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents our partners' share in net operating income of MarkWest Pioneer and Wirth Gathering Partnership. The increase resulted from the Arkoma Connector Pipeline being placed in service in July 2009.

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Northeast

 
  Three months ended
March 31,
   
   
 
 
  2010   2009   $ Change   % Change  
 
  (in thousands)
   
 

Revenue

  $ 111,848   $ 61,592   $ 50,256     82 %

Operating expenses:

                         
 

Purchased product costs

    67,087     50,954     16,133     32 %
 

Facility expenses

    4,225     5,165     (940 )   (18 )%
                     

Total operating expenses before items not allocated to segments

    71,312     56,119     15,193     27 %
                     

Operating income before items not allocated to segments

  $ 40,536   $ 5,473   $ 35,063     641 %
                     

        Revenue.    Revenue increased primarily due to higher commodity prices realized on NGL sales from the Appalachia region, as well as an increase in volumes from a significant customer.

        Purchased Product Costs.    Purchased product costs increased due to higher prices for the natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area, as well as the increase in volumes.

        Facility Expenses.    Facility expenses decreased primarily due to ceasing our natural gas gathering and processing operations in Western Michigan during the third quarter of 2009.

Liberty

 
  Three months ended
March 31,
   
   
 
 
  2010   2009   $ Change   % Change  
 
  (in thousands)
   
 

Revenue

  $ 19,010   $ 6,656   $ 12,354     186 %

Operating expenses:

                         
 

Purchased product costs

    2,584     826     1,758     213 %
 

Facility expenses

    7,313     2,539     4,774     188 %
                     

Total operating expenses before items not allocated to segments

    9,897     3,365     6,532     194 %
                     

Portion of operating income attributable to non-controlling interests

    3,637     280     3,357     1,199 %
                     

Operating income before items not allocated to segments

  $ 5,476   $ 3,011   $ 2,465     82 %
                     

        Revenue.    Revenue increased due to ongoing expansion of the Liberty facilities. Revenue increased approximately $5.8 million related to gathering fees and approximately $6.5 million related to NGL product sales under percent-of-proceeds arrangements.

        Purchased Product Costs.    Purchased product costs increased due to higher prices and increased purchases resulting from the ongoing expansion of the Liberty facilities.

        Facility Expenses.    Facility expenses increased primarily due to the ongoing expansion of the Liberty facilities, as well as an increase of approximately $1.1 million related to environmental remediation costs and other repairs and maintenance expense in 2010.

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        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents M&R's 40% interest in net operating income of MarkWest Liberty Midstream. The increase is the result of the formation of the joint venture on February 27, 2009.

Gulf Coast

 
  Three months ended
March 31,
   
   
 
 
  2010   2009   $ Change   % Change  
 
  (in thousands)
   
 

Revenue

  $ 19,793   $ 10,513   $ 9,280     88 %

Operating expenses:

                         
 

Facility expenses

    5,695     5,271     424     8 %
                     

Total operating expenses before items not allocated to segments

    5,695     5,271     424     8 %
                     

Operating income before items not allocated to segments

  $ 14,098   $ 5,242   $ 8,856     169 %
                     

        Revenue.    Revenue increased due to higher commodity prices and increased volumes. The volumes were lower in 2009 due to a two-week plant turnaround. The increase in revenue was partially offset by lower percent-of-proceeds received from one of our refinery customers under a variable percent-of-proceeds contract.

        Facility Expenses.    Facility expenses increased primarily due to the operating expenses of the SMR and increased utilities expense. The increases were partially offset by a decrease related to the plant turnaround completed in 2009 that did not recur in 2010.

Reconciliation of Segment Operating Income to Consolidated Income (Loss) Before Provision for Income Tax

        The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the three months ended March 31, 2010 and 2009. The ensuing items listed below the

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Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

 
  Three months ended
March 31,
   
   
 
 
  2010   2009   $ Change   % Change  
 
  (in thousands)
   
 

Total segment revenue

  $ 315,615   $ 183,367   $ 132,248     72 %
 

Derivative (loss) gain not allocated to segments

    (7,236 )   8,304     (15,540 )   (187 )%
                     
   

Total revenue

  $ 308,379   $ 191,671   $ 116,708     61 %
                     

Operating income before items not allocated to segments

  $ 128,460   $ 49,645   $ 78,815     159 %
 

Portion of operating income attributable to non-controlling interests

    5,137     308     4,829     1,568 %
 

Derivative loss not allocated to segments

    (19,819 )   (20,838 )   1,019     (5 )%
 

Compensation expense included in facility expenses not allocated to segments

    (722 )   (344 )   (378 )   110 %
 

Facility expenses adjustment

    539         539     N/A  
 

Selling, general and administrative expenses

    (21,508 )   (15,927 )   (5,581 )   35 %
 

Depreciation

    (28,187 )   (20,943 )   (7,244 )   35 %
 

Amortization of intangible assets

    (10,193 )   (10,233 )   40     (0 )%
 

Gain (loss) on disposal of property, plant and equipment

    9     (729 )   738     (101 )%
 

Accretion of asset retirement obligations

    (143 )   (47 )   (96 )   204 %
                       
   

Income (loss) from operations

    53,573     (19,108 )   72,681     (380 )%
 

Loss from unconsolidated affiliates

   
(68

)
 
(105

)
 
37
   
(35

)%
 

Interest income

    386     41     345     841 %
 

Interest expense

    (23,782 )   (17,782 )   (6,000 )   34 %
 

Amortization of deferred financing costs and discount (a component of interest expense)

    (2,612 )   (1,391 )   (1,221 )   88 %
 

Derivative gain related to interest expense

    1,871         1,871     N/A  
 

Miscellaneous income (expense), net

    1,062     (662 )   1,724     (260 )%
                     
   

Income (loss) before provision for income tax

  $ 30,430   $ (39,007 ) $ 69,437     (178 )%
                     

        Facility Expenses Adjustment.    Facility expenses adjustment consists of the reclassification of the MarkWest Pioneer field services fee and the reclassification of the interest expense related to the SMR which is included a facility expenses for the purposes of evaluating the performance of the Gulf Coast segment.

        Selling, General and Administrative Expenses.    Selling, general and administrative expenses increased primarily due to higher share-based compensation expense related to the January 2010 unrestricted unit grant. Increases in headcount, short-term incentive compensation, insurance and corporate office rent also contributed to the increase.

        Depreciation.    Depreciation increased due to depreciation on additional projects completed during 2009 and the first quarter of 2010.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in 2009 to fund our capital plan.

        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount increased due primarily to the amortization of the financing costs and discount on the Senior Notes issued in May 2009.

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        Derivative Gain Related to Interest Expense.    Derivative gain related to interest expense increased due to the settlement of all the outstanding interest rate swaps in January 2010. See Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements for further details.

        Provision for Income Tax.    The total provision for income tax expense was $4.4 million, which includes a deferred benefit of $1.4 million related primarily to MarkWest Hydrocarbon's ownership of Class A units and the net unrealized derivative loss during the period. The current provision for income tax expense was $5.8 million. Approximately $5.4 million is attributable to MarkWest Hydrocarbon and the remaining $0.4 million is related to taxes payable by the Partnership associated with the Texas Margin Tax and Michigan Business Taxes.

    Operating Data

 
  Three months ended
March 31,
   
 
 
  2010   2009   % Change  

Southwest

                   
 

East Texas

                   
   

Gathering systems throughput (Mcf/d)

    429,000     450,900     (4.9 )%
   

NGL product sales (gallons)

    64,195,800     48,370,000     32.7 %
 

Oklahoma

                   
   

Foss Lake gathering system throughput (Mcf/d)

    76,000     92,600     (17.9 )%
   

Stiles Ranch gathering system throughput (Mcf/d)

    115,800     93,300     24.1 %
   

Grimes gathering system throughput (Mcf/d)

    7,900     10,800     (26.9 )%
   

Arapaho NGL product sales (gallons)

    29,443,300     27,432,700     7.3 %
   

Southeast Oklahoma gathering system throughput (Mcf/d)

    496,600     418,600     18.6 %
   

Arkoma Connector Pipeline throughput (Mcf/d)(1)

    357,800     N/A     N/A  
 

Other Southwest

                   
   

Appleby gathering system throughput (Mcf/d)

    34,600     57,500     (39.8 )%
   

Other gathering systems throughput (Mcf/d)(2)

    9,000     10,700     (15.9 )%

Northeast

                   
 

Appalachia(3)

                   
   

Natural gas processed (Mcf/d)

    193,000     198,700     (2.9 )%
   

Keep-whole sales (gallons)

   
45,772,400
   
50,977,900
   
(10.2

)%
   

Percent-of-proceeds sales (gallons)

    27,005,000     19,363,000     39.5 %
                 
   

Total NGL product sales (gallons)(4)

    72,777,400     70,340,900     3.5 %
 

Michigan

                   
   

Crude oil transported for a fee (Bbl/d)

    12,900     12,800     0.8 %

Liberty

                   
   

Gathering system throughput (Mcf/d)

    100,900     33,600     200.3 %
   

NGL product sales (gallons)

    21,530,200     1,383,200     1,456.6 %

Gulf Coast

                   
   

Refinery off-gas processed (Mcf/d)

    113,300     104,200     8.7 %
   

Liquids fractionated (Bbl/d)

    22,500     20,000     12.5 %

(1)
We began commercial operation of the Arkoma Connector Pipeline in July 2009.

(2)
Excludes lateral pipelines where revenue is not based on throughput.

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(3)
Includes throughput from the Kenova, Cobb, and Boldman processing plants.

(4)
Represents sales at the Siloam fractionator. The total sales exclude 10,657,200 gallons and 1,383,200 gallons sold by the Northeast on behalf of Liberty for the three months ended March 31, 2010 and 2009, respectively.

Liquidity and Capital Resources

        Our primary strategy is to expand our asset base through organic growth and expansion projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit. In 2009, we spent approximately $487.0 million on internal development and expansion opportunities, of which a significant portion was funded by our joint venture partners and by our divestiture of the SMR facility.

        Our 2010 capital plan includes approximately $490 million to $540 million of capital expenditures for growth projects and approximately $10 million to $15 million for maintenance capital. Our share of growth capital expenditures is expected to be approximately $300 million to $350 million and the remainder will be funded through contributions from our joint venture partners and existing cash balances in the joint ventures. As of March 31, 2010 we have spent approximately $95.3 million, including the amounts funded by our joint venture partners.

        During the three months ended March 31, 2010, we received approximately $42.2 million from M&R to fund capital expenditures at MarkWest Liberty Midstream.

        Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private. We will also consider the use of alternative financing strategies such as entering into additional joint venture arrangements and the sale of non-strategic assets.

        Management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partners for capital projects encompassed by the joint venture, and our current borrowing capacity under the revolving credit facility. However, it may be necessary to raise additional funds to finance our future capital requirements. Our access to capital markets can be impacted by factors outside our control, including economic conditions; however, we believe that our strong cash flows and balance sheet, our credit facility and our credit rating will provide us with adequate access to funding given our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of May 3, 2010, our credit ratings were Ba3 with a Stable outlook by Moody's Investors Service and BB- with a Stable outlook by Standard & Poor's, which reflect upgrades by both agencies in 2010. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

    Debt Financing Activities

        Our revolving credit facility, which matures on February 20, 2012, has a borrowing capacity of $435.6 million with an accordion feature of up to $200.0 million of uncommitted funds. Under the provisions of the Partnership Credit Agreement we are subject to a number of restrictions and covenants. As of March 31, 2010, we were in compliance with all of our debt covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of May 3, 2010, we had no borrowings outstanding and $37.5 million of letters of credit outstanding under the revolving credit facility, leaving approximately $398.1 million available for borrowing.

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        As of March 31, 2010, we had four series of Senior Notes outstanding: $225.0 million aggregate principal issued in October 2004 and due November 2014; $150.0 million aggregate principal issued in May 2009 and due November 2014 with terms substantially the same as the 2014 Senior Notes; $275.0 million aggregate principal issued in July 2006 and due July 2016; and $500.0 million aggregate principal issued in April and May 2008 and due April 2018. For further discussion of the Senior Notes see Note 7 of the accompanying Notes to the Condensed Consolidated Financial Statements.

        The indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries. The indentures place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

        The Partnership Credit Agreement limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Partnership Credit Agreement prevents members of the participating bank group from requiring margin calls. As of May 3, 2010, approximately 96% of our derivative positions, measured volumetrically, are with members of the participating bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit; however, there is no certainty that the members of our bank group will continue to participate and in such case, a portion of our available credit could be used for derivative instruments instead of future growth.

    Equity Offerings

        On April 6, 2010, we completed a public offering of approximately 4.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option, at a price of $30.43 per common unit. Net proceeds of approximately $142.0 million will be used to partially fund our ongoing capital expenditure program and to repay borrowings under our revolving credit facility.

    Liquidity Risks and Uncertainties

        Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance. That, in turn, will be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control. The global economic recession had a significant adverse impact on commodity prices during 2009. Although NGL and natural gas prices have improved in the first quarter of 2010 compared to 2009, our operating performance could be negatively impacted if the improvements in commodity prices are not sustained. Additionally, new legislation currently being considered by Congress could limit our ability to execute our hedging strategy, which would increase our exposure to adverse changes in commodity prices.

        The prevailing uncertainty that exists in the financial markets has created an increased risk of counterparty default that could impact our liquidity in several ways. During 2010, we expect that we will be required to borrow additional amounts under our revolving credit facility. However, our ability to access these funds could be adversely impacted by the failure of one or more of the members of the participating bank group. Although management believes that the participating members are financially sound, an increased risk does exist. Also, because the participating members of our bank group are the

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counterparties to most of our derivative instruments, the failure of one of more members could significantly reduce the cash flow from operations related to the settlement of these positions. The cash flows generated by our operations could also be significantly reduced if any of our major customers defaulted on its obligations to us. The creditworthiness of our trade customers is continuously monitored, and we believe that our current group of customers are sound and do not represent abnormal credit risk. Additionally, our supply of gas is dependent on a few large producers in each of our operating segments. If any of these producers were forced to significantly curtail or cease production due to economic adversity, our cash flows from operations could be significantly reduced.

    Cash Flow

        The following table summarizes cash inflows (outflows) (in thousands):

 
  Three months ended
March 31,
   
 
 
  2010   2009   $ Change  

Net cash provided by operating activities

  $ 114,360   $ 91,820   $ 22,540  

Net cash flows used in investing activities

    (95,030 )   (175,051 )