Markwest Energy Partners L P 10-Q 2008 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2008

OR

oTRANSITION 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 x 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. (Check one):

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

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  x

The number of the registrant’s common units outstanding as of August 4, 2008, was 56,639,952.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2008 and December 31, 2007	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2008 and 2007	3
	Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital and Comprehensive Income for the six months ended June 30, 2008	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2007	5
	Unaudited Notes to the Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	50
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults Upon Senior Securities	51
Item 4.	Submission of Matters to a Vote of Security Holders	52
Item 5.	Other Information	52
Item 6.	Exhibits	53
SIGNATURES		54

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.

As explained further in Item 1, Notes to the Condensed Consolidated Financial Statements, Note 1. Organization and Basis of Presentation, on February 21, 2008, MarkWest Energy Partners, L.P. completed its plan of redemption and merger (the “Merger”) with MarkWest Hydrocarbon, Inc. (the “Corporation”) and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership, pursuant to which the Corporation was merged into the Partnership. The Merger was considered a downstream merger whereby the Corporation was viewed as the surviving consolidated entity for accounting purposes rather than the Partnership, which is the surviving consolidated entity for legal purposes. As such, the Merger was accounted for in the Corporation’s condensed consolidated financial statements as an acquisition of non-controlling interest using the purchase method of accounting.  As a result, the historical and comparative condensed consolidated financial statements of the surviving legal entity are those of the Corporation, the accounting acquirer, rather than those of the Partnership, the legal acquirer.  Under the Merger, the shareholders of the Corporation exchanged each share of Corporation common stock for consideration equal to 1.9051 Partnership common units (the “Exchange Ratio”).  All historical unit and per unit data has been adjusted to reflect the Exchange Ratio to give the effect of the Merger.

Glossary of Terms

Bbl/d	barrels of oil per day
Btu	one British thermal unit, an energy measurement
EBITDA	Earnings Before Interest, Taxes, Depreciation and Amortization
Gal/d	gallons per day
Mcf/d	one thousand cubic feet of natural gas per day
MMBtu	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)	revenues less purchased product costs
NGL	natural gas liquids, such as propane, butanes and natural gasoline

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	June 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	278,313		$	37,695
Trading securities	—			3,674
Available for sale securities	—			6,474
Receivables, net of allowances of $181 and $194, respectively	151,517			130,877
Inventories	37,721			30,328
Fair value of derivative instruments	36,389			9,441
Derivative premiums	4,321			—
Deferred income taxes	17,055			16,667
Other current assets	14,776			51,178
Total current assets	540,092			286,334
Property, plant and equipment	1,207,150			976,169
Less: accumulated depreciation	(46,374		)	(145,360		)
Total property, plant and equipment, net	1,160,776			830,809
Other long-term assets:
Investment in unconsolidated affiliates	80,887			58,709
Intangibles, net of accumulated amortization of $21,808 and $45,753, respectively	700,211			326,722
Goodwill	37,461			—
Deferred financing costs, net of accumulated amortization of $1,928 and $8,206, respectively	17,954			13,428
Deferred contract cost, net of accumulated amortization of $1,170 and $1,014, respectively	2,080			2,236
Deferred tax asset	37,450			—
Fair value of derivative instruments	40,169			5,414
Derivative premiums	10,743			717
Other long-term assets	1,524			326
Total other long-term assets	928,479			407,552
Total assets	$	2,629,347		$	1,524,695
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	144,100		$	107,107
Accrued liabilities	118,007			79,869
Fair value of derivative instruments	180,589			77,426
Total current liabilities	442,696			264,402
Deferred income taxes	3,420			8,500
Fair value of derivative instruments	287,660			84,051
Long-term debt, net of discounts of $12,683 and $2,805, respectively	987,317			552,695
Other long-term liabilities	4,188			51,073
Non-controlling interest in consolidated subsidiary	—			524,583
Commitments and contingencies (Note 19)
Partners’ Capital:
Common units, 56,626 and 22,861 units outstanding, respectively	904,066			38,463
Accumulated other comprehensive income, net of tax	—			928
Total partners’ capital	904,066			39,391
Total liabilities and partners’ capital	$	2,629,347		$	1,524,695

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 June 30,						Six months ended June 30,
	2008			2007			2008			2007
Revenue:
Revenue	$	278,158		$	198,788		$	563,200		$	390,408
Derivative loss	(312,591		)	(13,913		)	(358,841		)	(27,822		)
Total revenue	(34,433		)	184,875			204,359			362,586
Operating expenses:
Purchased product costs	153,273			125,067			308,208			247,124
Derivative (gain) loss related to purchased product costs	(47,097		)	6,335			(79,094		)	4,708
Facility expenses	24,762			17,386			47,428			29,881
Derivative (gain) loss related to facility expenses	(310		)	1,029			(353		)	596
Selling, general and administrative expenses	16,614			18,811			39,075			39,381
Depreciation	16,498			9,325			31,023			17,499
Amortization of intangible assets	10,469			4,168			17,318			8,336
Loss on disposal of property, plant and equipment	—			9			3			154
Accretion of asset retirement obligations	33			28			65			55
Impairment of long-lived assets	5,009			—			5,009			—
Total operating expenses	179,251			182,158			368,682			347,734
(Loss) income from operations	(213,684		)	2,717			(164,323		)	14,852
Other income (expense):
Earnings from unconsolidated affiliates	577			1,656			2,128			3,423
Interest income	1,662			1,124			2,176			3,520
Interest expense	(17,450		)	(9,054		)	(28,599		)	(18,468		)
Amortization of deferred financing costs and discount (a component of interest expense)	(5,164		)	(731		)	(6,207		)	(1,451		)
Miscellaneous income (expense)	1,175			(317		)	1,142			(1,067		)
(Loss) income before non-controlling interest in net income of consolidated subsidiary and provision for income tax	(232,884		)	(4,605		)	(193,683		)	809
Non-controlling interest in net (loss) income of consolidated subsidiary	—			(5,562		)	3,393			(9,522		)
Loss before provision for income tax	(232,884		)	(10,167		)	(190,290		)	(8,713		)
Provision for income tax (expense) benefit:
Current	(4,565		)	(9,848		)	(15,332		)	(10,649		)
Deferred	59,682			12,743			47,006			13,047
Total provision for income tax	55,117			2,895			31,674			2,398
Net loss	$	(177,767	)	$	(7,272	)	$	(158,616	)	$	(6,315	)
Net loss per common unit (1) (Note 17):
Basic	$	(3.19	)	$	(0.32	)	$	(3.50	)	$	(0.28	)
Diluted	$	(3.19	)	$	(0.32	)	$	(3.50	)	$	(0.28	)
Weighted average number of outstanding common units (1):
Basic	55,742			22,854			45,326			22,844
Diluted	55,742			22,854			45,326			22,844
Cash distribution declared per common unit (1)	$	0.60		$	0.17		$	0.79		$	0.33

(1)  All unit and per unit data where applicable has been adjusted to reflect the 1.9051 Exchange Ratio to give the effect to the redemption and merger between MarkWest Hydrocarbon, Inc. and MarkWest Energy Partners, L.P. on February 21, 2008 (see Note 3). The Partnership declared a distribution of $0.63 per common unit on July 24, 2008, for the period ended June 30, 2008, and $0.60 per common unit on April 24, 2008, for the period ended March 31, 2008 (see Note 18).

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statement of Changes in Partners’ Capital and Comprehensive Income

(unaudited, in thousands)

	Common Units (1)		Partners’ Capital			Accumulated Other Comprehensive Income			Total
December 31, 2007	22,861		$	38,463		$	928		$	39,391
Option exercises	98		375			—			375
Dividends paid	—		(4,338		)	—			(4,338		)
Distributions paid	—		(34,463		)	—			(34,463		)
Share-based compensation related to equity awards	—		5,051			—			5,051
APIC pool for excess tax benefits under SFAS 123R	—		717			—			717
Merger and Redemption:
Redemption of MarkWest Hydrocarbon, Inc. common stock	(7,458	)	(240,513		)	—			(240,513		)
Conversion of restricted stock to phantom units in connection with the Merger	(45	)	—			—			—
Acquisition of General Partnership’s minority interest associated with the Merger	946		30,078			—			30,078
Purchase of minority interest of MarkWest Energy Partners, L.P.	34,474		1,095,917			—			1,095,917
Issuance of units in public offering, net of offering costs	5,750		171,395			—			171,395
Net loss	—		(158,616		)	—			(158,616		)
Realized gain on marketable securities, net of taxes of $558	—		—			(928		)	(928		)
Comprehensive loss	—		—			—			(159,544		)
June 30, 2008	56,626		$	904,066		$	—		$	904,066

(1)  All unit and per unit data where applicable has been adjusted to reflect the 1.9051 Exchange Ratio to give the effect to the redemption and merger between MarkWest Hydrocarbon, Inc. and MarkWest Energy Partners, L.P. on February 21, 2008 (see Note 3).

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)

	Six months ended June 30,
	2008			2007
Cash flows from operating activities:
Net loss	$	(158,616	)	$	(6,315	)
Adjustments to reconcile net loss to net cash provided by operating activities (net of acquisitions):
Depreciation	31,023			17,499
Amortization of intangible assets	17,318			8,336
Impairment of long-lived assets	5,009			—
Amortization of deferred financing costs and discount	6,207			1,451
Accretion of asset retirement obligation	65			55
Amortization of gas contract	156			156
Phantom unit compensation expense	6,174			1,179
Participation Plan compensation expense	4,545			13,773
Restricted stock compensation expense	75			373
Non-controlling interest in net (income) loss of consolidated subsidiary	(3,393		)	9,522
Equity in earnings of unconsolidated affiliates	(2,128		)	(3,423		)
Distributions from equity investments	3,570			6,189
Unrealized loss on derivative instruments	245,069			36,613
Loss on disposal of property, plant and equipment	3			154
Deferred income taxes	(47,006		)	(13,020		)
Unrealized gain on trading securities	—			(9		)
Net purchase of trading securities	—			(15,797		)
Gain on sale of available for sale securities	(1,238		)	—
Loss on sale of trading securities	104			—
Net sales of trading securities	2,400			—
Other	(6		)	(118		)
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(20,640		)	(25,332		)
Inventories	(7,393		)	(1,566		)
Other current assets and derivative premiums	32,081			(11,020		)
Accounts payable and accrued liabilities	60,548			13,478
Other long-term assets and derivative premiums	(10,026		)	—
Other long-term liabilities	57			186
Net cash provided by operating activities	163,958			32,364
Cash flows from investing activities:
Additional acquisition costs	—			(46		)
Equity investments	(23,620		)	—
Cash paid to acquire General Partnership’s minority interest	(21,484		)	—
Cash paid in merger for MarkWest Hydrocarbon, Inc. stock	(248,395		)	—
Proceeds from sale of available for sale securities	6,226			—
Capital expenditures	(172,188		)	(140,711		)
Proceeds from disposal of property, plant and equipment	8			30
Net cash flows used in investing activities	(459,453		)	(140,727		)
Cash flows from financing activities:
Proceeds from long-term debt	958,234			189,500
Payments of long-term debt	(515,001		)	(187,500		)
Payments for debt issuance costs, deferred financing costs and registration costs	(21,155		)	(462		)
Proceeds from private placements, net	—			134,950
Proceeds from public offering, net	171,395			—
Exercise of stock options	375			114
APIC pool for excess tax benefits under SFAS 123R	717			91
Payment of dividends and distributions	(38,801		)	(7,435		)
Distributions to MarkWest Energy unitholders	(19,651		)	(29,830		)
Net cash flows provided by financing activities	536,113			99,428
Net increase (decrease) in cash	240,618			(8,935		)
Cash and cash equivalents at beginning of year	37,695			48,844
Cash and cash equivalents at end of period	$	278,313		$	39,909

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

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	Six months ended June 30,
	2008		2007
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	19,141	$	31,577
Cash paid for income taxes	9,603		3,937
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	32,851	$	39,269
Interest capitalized on construction in progress	2,654		2,272
Property, plant and equipment asset retirement obligation	9		144
Merger step-up of fair value	605,100		—

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. (the “Partnership”) was formed on January 25, 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 natural gas liquids, or NGLs, and the gathering and transportation of crude oil. The Partnership has extensive natural gas gathering, processing and transmission operations in the southwestern and Gulf Coast regions of the United States and is the largest natural gas processor in the Appalachian region.

On February 21, 2008, the Partnership completed the transactions contemplated by its plan of redemption and merger (the “Merger”) with MarkWest Hydrocarbon, Inc. (the “Corporation”) and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership.   As a result of the Merger, MarkWest Hydrocarbon is now a wholly-owned subsidiary of the Partnership (see Note 3).  Unless otherwise indicated or the context otherwise requires, all references in this report to “MarkWest Energy Partners,” the “Partnership,” “us,” “our” or “we” are to MarkWest Energy Partners, L.P.  Except as otherwise specified, references to “MarkWest Hydrocarbon” or “the Corporation” are to MarkWest Hydrocarbon, Inc.

The Merger was accounted for in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 141, Business Combinations (“SFAS 141”) and related interpretations. The Merger was considered a downstream merger, whereby the Corporation was viewed as the surviving consolidated entity for accounting purposes rather than the Partnership, which is the surviving consolidated entity for legal purposes. As such, the Merger was accounted for in the Corporation’s condensed consolidated financial statements as an acquisition of non-controlling interest using the purchase method of accounting. Under this accounting method, the Partnership’s accounts, including goodwill, were adjusted to proportionately step up the book value of certain assets and liabilities. As a result, the historical and comparative condensed consolidated financial statements of the surviving legal entity are those of the Corporation, the accounting acquirer, rather than those of the Partnership, the legal acquirer.

The Partnership’s unaudited condensed consolidated financial statements include the accounts of all majority-owned or majority-controlled subsidiaries.  Equity 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.  These condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) 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.  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.  In addition to reviewing these condensed consolidated financial statements and accompanying notes, you should also consult the audited financial statements and accompanying notes included in the Partnership’s December 31, 2007 Annual Report on Form 10-K, as amended, and its Current Report filed on Form 8-K/A on March 14, 2008.  Finally, consider that results for the three and six months ended June 30, 2008, are not necessarily indicative of results for the full year 2008, or any other future period.

Goodwill

As a result of the Merger, goodwill was recorded on the Partnership’s balance sheet. The carrying value of goodwill was $37.5 million at June 30, 2008. Goodwill will be reviewed for impairment annually as of November 30, or more frequently, when events and circumstances occur indicating that the recorded goodwill may not be recoverable.  If the carrying value of goodwill exceeds the implied fair value, an impairment loss is recorded in an amount equal to that excess.

2.Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The Partnership adopted SFAS 157 on January 1, 2008 (see Note 4). On February 12, 2008, the FASB issued FASB Staff Position No. FAS 157-2 that defers the effective date of SFAS 157 for non-financial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a reoccurring basis (at least annually) until fiscal years beginning after November 15, 2008. The Partnership deferred recognition of items including:

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·Nonfinancial assets and liabilities initially measured at fair value in a business combination or other new basis event, but not measured at fair value in subsequent periods (nonrecurring fair value measurements).

·Reporting units measured at fair value in the first and second steps of a goodwill impairment test as described in paragraphs 19 to 21 of SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS 142”).

·Indefinite lived intangible assets measured at fair value for impairment assessment under SFAS 142.

·Long-lived assets measured at fair value for impairment assessment under SFAS No. 144, Accounting for Impairment or Disposal of Long Lived Assets (“SFAS 144”).

·Asset retirement obligations initially measured at fair value under SFAS No. 143, Accounting for Asset Retirement Obligations.

·Liabilities for exit or disposal activities initially measured at fair value under SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (“SFAS 146”).

The adoption of SFAS 157 had an effect of a $1.1 million decrease to fair value of derivative instruments liability, a decrease to Revenue - derivative loss of $0.4 million and an increase to derivative gain related to purchase product costs of $0.7 million.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), which permits an entity to measure certain financial assets and financial liabilities at fair value. The statement’s objective is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS 159, entities that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. SFAS 159 was effective for the Partnership as of January 1, 2008. The adoption of SFAS 159 did not impact the Partnership’s condensed consolidated financial statements since the Partnership did not elect the fair value option.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141R”). This statement replaces SFAS 141, Business Combinations. The statement provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed and any non-controlling interest in the acquiree. SFAS 141R provides for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. The statement determines what information to disclose to enable users to evaluate the nature and financial effects of the business combination. The provisions of SFAS 141R are effective for the Partnership as of January 1, 2009, and do not allow early adoption. The Partnership is currently evaluating the impact of adopting SFAS 141R.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (“SFAS 160”). This statement provides that noncontrolling interests in subsidiaries held by parties other than the parent be identified, labeled and presented in the statement of financial position within equity, but separate from the parent’s equity. SFAS 160 states that the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified on the consolidated statement of income. The statement provides for consistency regarding changes in parent ownership including when a subsidiary is deconsolidated. Any retained non-controlling equity investment in the former subsidiary will be initially measured at fair value. The provisions of SFAS 160 are effective for the Partnership as of January 1, 2009, and do not allow early adoption. The Partnership is currently evaluating the impact of adopting SFAS 160.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and requires entities to provide enhanced qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair values and amounts of gains and losses on derivative contracts, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 will be effective for the Partnership’s fiscal 2009 interim and annual consolidated financial statements.  The principal impact to the Partnership will be to require expanded disclosure regarding derivative instruments.

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In April 2008, the FASB issued Staff Position No. FAS 142-3 (“FSP 142-3”), Determination of the Useful Life of Intangible Assets. FSP 142-3 amends the factors that an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under FASB Statement No. 142 (“SFAS 142”), Goodwill and Other Intangible Assets. In determining the useful life of an acquired intangible asset, FSP 142-3 removes the requirement from SFAS 142 for an entity to consider whether renewal of the intangible asset requires significant costs or material modifications to the related arrangement. FSP 142-3 also replaces the previous useful life assessment criteria with a requirement that an entity considers its own experience in renewing similar arrangements. If the entity has no relevant experience, it would consider market participant assumptions regarding renewal.  FSP142-3 will be effective as of January 1, 2009 and will apply only to intangible assets acquired after that date. Retroactive application to previously acquired intangible assets is prohibited.  The adoption of FSP 142-3 is not expected to have a material impact on the Partnership’s condensed consolidated financial statements.

In June 2008, the FASB issued Staff Position EITF 03-6-1 (“FSP EITF 03-6-1”), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. FSP EITF 03-6-1 states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method as described in SFAS No. 128, Earnings per Share. FSP EITF 03-6-1 is effective for the Partnership beginning January 1, 2009.  Upon adoption, the Partnership is required to retrospectively adjust its earnings per share data to conform to the provisions in FSP EITF 03-6-1. However, early application of the provisions is prohibited. The Partnership is currently evaluating the impact of adopting FSP EITF 03-6-1.

3.Redemption and Merger

On February 21, 2008, the Partnership completed the transactions contemplated by its plan of redemption and merger with the Corporation and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership. Under the Merger, the shareholders of the Corporation exchanged each share of Corporation common stock for consideration equal to 1.9051 Partnership common units (“Exchange Ratio”).  This Exchange Ratio was computed based on the stated consideration of 1.285 Partnership common units plus $20 in cash, or equivalent value.  In accordance with the merger agreement, the equivalent value was based on a Partnership common unit price of $32.25, which equals the average market price of Partnership common units for the ten day period ending three days prior to the closing date. Therefore, the $20.00 in cash was equivalent to 0.6201 Partnership common units which results in a total Exchange Ratio of 1.9051 when combined with the other 1.285 units included in the stated consideration.  Subject to pro ration, the shareholders elected to receive this consideration either entirely in cash in the redemption, entirely in Partnership common units in the Merger, or in any combination of cash and Partnership common units with equivalent value.  The Corporation redeemed for $240.5 million in cash those shares of Corporation common stock electing to receive cash. Immediately after the redemption, the Partnership acquired the Corporation through a merger of MWEP, L.L.C. with and into the Corporation, pursuant to which all remaining shares of the Corporation’s common stock were converted into approximately 15.5 million Partnership common units. As a result of the Merger, the Corporation is a wholly-owned subsidiary of the Partnership. In connection with the Merger, the incentive distribution rights in the Partnership, the 2% economic interest in the Partnership held by MarkWest Energy GP, L.L.C. (the “General Partner”) and the Partnership common units owned by the Corporation were exchanged for Partnership Class A units. Contemporaneously with the closing of the transactions contemplated by the Merger, the Partnership separately acquired 100% of the Class B membership interests in the General Partner that had been held by current and former management and certain directors of the Corporation and the General Partner. Additionally, as a result of the redemption and merger, the Partnership assumed the 2006 Hydrocarbon Stock Incentive Plan and the 1996 Hydrocarbon Stock Incentive Plan (see Note 15).

Using the Exchange Ratio, the number of Corporation shares outstanding as of December 31, 2007 and activity through February 21, 2008 has been adjusted to the equivalent number of Partnership common units in the accompanying Condensed Consolidated Financial Statements. The following table illustrates these conversions (shares and units in thousands):

	Common		Exchange	Common
	Shares		Ratio	Units
Shares of Corporation Common Stock Outstanding at December 31, 2007	11,999.8		1.9051	22,861
Stock Option exercises in first quarter 2008, prior to merger	51.5		1.9051	98
Conversion of Restricted Shares to Partnership Phantom units	(23.8	)	1.9051	(45	)
Shares eligible for redemption or conversion to Partnership Units	12,027.5			22,914
Common shares tendered for redemption in cash	(3,914.5	)	1.9051	(7,458	)
Common shares tendered for conversion to Partnership common units	8,113.0		1.9051	15,456

Class A units represent limited partner interests in the Partnership and have identical rights and obligations of the Partnership common units except that Class A units (a) do not have the right to vote on, approve or disapprove, or otherwise consent to or not

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consent to any matter (including mergers, share exchanges and similar statutory authorizations) except as otherwise required by any non-waivable provision of law and (b) do not share in any cash and cash equivalents on hand, income, gains, losses, deductions and credits that are derived from or attributable to the Partnership’s ownership of, or sale or disposition of, the shares of MarkWest Hydrocarbon common stock.  Pursuant to Accounting Research Bulletin No. 51, Consolidated Financial Statements, the Class A units held by the Corporation and the General Partner are not treated as outstanding common units in the Condensed Consolidated Balance Sheet.

The total fair value of the non-controlling interest acquired was the number of non-controlling interest units outstanding on the date the Merger closed valued at the then current per unit market price of the Partnership common units of $31.79.   The following table shows the calculation of the purchase price of the Partnership ($ in thousands):

	Units	Dollars
Fair value of units held prior to merger	34,473,647	$	1,095,917
Add: Direct costs of the Merger		7,882
		$	1,103,799

Significant fair value estimates were required for the following assets and liabilities:

·Property, plant, and equipment — The fair value estimates for property, plant and equipment were based primarily on the cost approach, which considers both historical cost and replacement cost. Additionally, the Partnership estimated the remaining useful lives of the property, plant and equipment to ensure that the useful lives used for depreciation subsequent to the Merger are reasonable and consistent with the Partnership’s accounting policy.

·Intangible assets — The fair value estimates for customer relationships were based on a version of the income approach. The income approach involves estimating future cash flows from existing customer relationships and making provisions for a fair return on other recognized contributory assets. Key assumptions in the valuation include contract renewals, economic incentives to retain customers, historic volumes, current and future capacity in the gathering system, pricing volatility and the discount rate. The estimated useful life of the intangible assets was determined by assessing the estimated useful life of the other assets to which the contracts and relationships relate, likelihood of renewals, projected reserves, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

·Long-term debt — The fair value of the Partnership’s Senior Notes was estimated using a high yield market price at which our debt was trading as of the date the Merger closed.

·Deferred finance costs — The deferred finance costs of the Partnership have no fair market value as of the date the Merger closed. Therefore 85.7% of these costs are written-off under the purchase method of accounting.

The remaining purchase price in excess of the fair values of the assets and liabilities acquired was recorded as goodwill.

The following table shows the final purchase price allocation as of February 21, 2008 (in thousands):

	Original Net Book Value			Fair Value			85.7% Proportional Step-Up of Fair Value			Average Depreciable Life
Property, plant and equipment	$	843,122		$	1,051,408		$	178,501		18
Intangible assets	324,326			780,343			390,807			18
Long-term debt	(581,642		)	(570,775		)	9,313			8
Deferred financing costs	12,815			—			(10,982		)	8
Goodwill							37,461
Total Adjustments							605,100
Deferred income taxes	n/a			n/a			(3,598		)
Non-controlling interest							502,297
Total Purchase Price							$	1,103,799

n/a—Amounts represent the recognition of deferred tax liabilities related to temporary tax differences that are expected to reverse in future periods related to the proportional step-up of fair value due to the Merger.  No deferred tax liabilities related to goodwill were recognized as goodwill is not deductible for tax purposes.

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4.Fair Value

Fair Value Measurement

The Partnership adopted SFAS 157 on January 1, 2008.  SFAS 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions.  SFAS 157 applies to all fair value measurements however the FASB deferred the effective date for certain nonfinancial assets and liabilities until January 1, 2009 (see Note 2).  SFAS 157 applies principally to the Partnership’s derivative positions and trading securities at June 30, 2008.  Additional key provisions of the statement include:

·Defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, and establishes a framework for measuring fair value;

·Establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date;

·Nullifies the guidance in Emerging Issues Task Force Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Involved in Energy Trading and Risk Management Activities, which required the deferral of profit at inception of a transaction involving a derivative financial instrument in the absence of observable data supporting the valuation technique;

·Eliminates large position discounts for financial instruments quoted in active markets and requires consideration of the Firm’s creditworthiness when valuing liabilities; and

·Expands disclosures about instruments measured at fair value.

Valuation Hierarchy

SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

·Level 1 — inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

·Level 2 — inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

·Level 3 — inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  Following is a description of the valuation methodologies the Partnership used for instruments measured at fair value, as well as the general classification of such instruments pursuant to the valuation hierarchy.

Commodity Derivative Transactions

The Partnership utilizes a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available in the over-the-counter (“OTC”) market, and futures contracts.  The Partnership’s derivative positions are valued using corroborated market data and internally developed models when observable market data is not available.  Commodity transactions based on crude oil and natural gas are considered Level 2 transactions as the pricing methodology include quoted prices for similar assets and liabilities and the Partnership can determine the prices are observable and do not contain Level 3 inputs that are significant to the measurement.  Natural gas liquid positions have significant unobservable market parameters and are normally traded less actively or have trade activity that is one way, and therefore are classified within Level 3 of the valuation hierarchy.

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Trading Securities

Trading securities consist exclusively of auction rate securities as of June 30, 2008 and are included in Other long-term assets in the accompanying Condensed Consolidated Balance Sheets. Quoted market prices are not available and these securities’ fair values are estimated by using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows. Considering observable market activity is not available for these securities, the securities are classified within Level 3 of the valuation hierarchy.

The methods 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 June 30, 2008.

The following table presents the financial instruments carried at fair value as of June 30, 2008, by caption on the Condensed Consolidated Balance Sheet and by SFAS 157 valuation hierarchy (as described above, in thousands):

	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs  (Level 2)			Significant unobservable inputs (Level 3)			Total carrying value in Consolidated Balance Sheet
Assets:
Fair value of derivative instruments	$	—	$	90,380		$	1,242		$	91,622
Other long-term assets	—		—			1,198			1,198
Total assets at fair value	$	—	$	90,380		$	2,440		$	92,820
Liabilities:
Fair value of derivative instruments	$	—	$	(444,487	)	$	(23,762	)	$	(468,249	)
Total liabilities at fair value	$	—	$	(444,487	)	$	(23,762	)	$	(468,249	)

Changes in Level 3 fair value measurements

The tables below include a rollforward of the balance sheet amounts for the three and six months ended June 30, 2008 (including the change in fair value) for financial instruments classified by the Partnership within Level 3 of the valuation hierarchy (in thousands). When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. However, Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources); accordingly, the gains and losses in the table below include changes in fair value due in part to observable factors that are part of the valuation methodology.

	Fair value measurements using significant unobservable inputs (Level 3)
	Fair value March 31, 2008			Total gains or losses (realized or unrealized) included in earnings			Purchases issuances and settlements			Transfers in or out of Level 3		Fair value June 30, 2008
Assets:
Derivatives	$	305		$	937	(a)	$	—		$	—	$	1,242
Trading securities	1,198			—		(b)	—			—		1,198
Liabilities:
Derivatives	(16,976		)	(3,075		)(a)	(3,711		)	—		(23,762		)

(a)  Gains and losses are recorded in derivative (loss) gain in revenue, purchased product costs or facility expenses.

(b)  Gains and losses recorded in miscellaneous expense.

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	Fair value measurements using significant unobservable inputs (Level 3)
	Fair value January 1, 2008			Total gains or losses (realized or unrealized) included in earnings			Purchases issuances and settlements			Transfers in or out of Level 3		Fair value June 30, 2008
Assets:
Derivatives	$	111		$	1,131	(a)	$	—		$	—	$	1,242
Trading securities	3,674			(76		)(b)	(2,400		)	—		1,198
Liabilities:
Derivatives	(36,828		)	27,968		(a)	(14,902		)	—		(23,762		)

(a)  Gains and losses are recorded in derivative (loss) gain in revenue, purchased product costs or facility expenses.

(b)  Gains and losses recorded in miscellaneous expense.

Assets and liabilities measured at fair value on a nonrecurring basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the instruments are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.  As of June 30, 2008, there were not any assets or liabilities to be measured at fair value on a nonrecurring basis.

5.Marketable Securities

As of December 31, 2007, the Partnership held short-term equity investments classified as Trading securities.  During the first six months of 2008, the market mechanism normally used to liquidate the trading securities was no longer operating efficiently.  It is not known if the Partnership will be able to sell these investments within the next year. Therefore as of June 30, 2008, the $1.2 million balance associated with these securities has been reclassified to Other long-term assets in the accompanying Condensed Consolidated Balance Sheets.

The following are the components of marketable securities (in thousands):

	Cost Basis		Net Unrealized Gains			Fair Value
June 30, 2008
Equity Securities:
Trading Securities	$	1,198	$	—		$		1,198
	Cost Basis		Net Unrealized Gains (Losses)			Fair Value
December 31, 2007
Equity Securities:
Trading Securities	$	3,698	$	(24	)	$		3,674
Available for Sale Securities	4,988		1,486			6,474
	$	8,686	$	1,462		$	10,148

The Partnership recognized an other than temporary loss of zero and $0.1 million on its trading securities during the three and six months ended June 30, 2008, respectively. This loss is included in Miscellaneous income (expense) in the accompanying Condensed Consolidated Statements of Operations.

The Partnership realized gains from the sale of available-for-sale securities of zero and $1.2 million for the three and six months June 30, 2008, respectively. These gains are included in Miscellaneous income (expense) in the accompanying Condensed Consolidated Statements of Operations.

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6.Receivables and Other Current Assets

Receivables consist of the following (in thousands):

	June 30,		December 31,
	2008		2007
Trade, net	$	145,886	$	121,099
Other	5,631		9,778
Total receivables	$	151,517	$	130,877

Other current assets consist of the following (in thousands):

	June 30,		December 31,
	2008		2007
Margin deposits	$	—	$	40,260
Prepaid fuel	10,618		1,605
Income tax receivable	84		3,212
Merger finance costs	—		857
Prepaid merger costs	—		3,914
Prepaid insurance	2,575		333
Prepaid other	1,499		997
Total other current assets	$	14,776	$	51,178

7.Property, Plant and Equipment

Property, Plant and Equipment consist of the following (in thousands):

	June 30,			December 31,
	2008			2007
Natural gas gathering facilities, natural gas pipelines and other	$	794,043		$	657,878
Gas processing plants	225,526			213,414
Fractionation and storage facilities	24,661			24,388
Crude oil pipelines	16,104			21,588
NGL transportation facilities	10,888			4,676
Furniture, office equipment and other	1,304			2,672
Construction in progress	134,624			51,553
Property, plant and equipment	$	1,207,150		$	976,169
Less: accumulated depreciation	(46,374		)	(145,360		)
Total property, plant and equipment, net	$	1,160,776		$	830,809

The Partnership capitalizes interest on major projects during construction.  For the three and six months ended June 30, 2008, the Partnership capitalized interest, including deferred finance costs, of $1.6 million and $2.7 million, respectively.  For three and six months ended June 30, 2007, the Partnership capitalized interest, including deferred finance costs, of $1.1 million and $2.3 million, respectively.

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8.Intangible Assets and Goodwill

The Partnership’s intangible assets, net of accumulated amortization, at June 30, 2008 and December 31, 2007, are comprised of customer contracts and relationships, as follows (in thousands):

	June 30,		December 31,
Segment	2008		2007
Southwest	$	377,976	$	148,488
Northeast	66,126		—
Gulf Coast	256,109		178,234
Total	$	700,211	$	326,722

Amortization expense related to the intangible assets was $10.5 million and $4.2 million for the three months ended June 30, 2008 and 2007, respectively, and $17.3 million and $8.3 million for the six months ended June 30, 2008 and 2007, respectively.

The purchase price in excess of the fair value of the minority interest in the net assets and liabilities of the Partnership at the time of the Merger between MarkWest Energy Partners and MarkWest Hydrocarbon was recorded as goodwill. In accordance with SFAS 142, goodwill is not amortized but instead tested for impairment annually, or more frequently when events and circumstances occur indicating that the recorded goodwill may not be recoverable.  As of June 30, 2008, goodwill was $37.5 million.  The Partnership did not have goodwill recorded prior to the Merger.

9.Equity Investments

On March 1, 2008, the Partnership acquired a 20% interest in Centrahoma Processing, LLC (“Centrahoma”) for $11.6 million, which is accounted for under the equity method.  On May 9, 2008, the Partnership exercised its option to acquire an additional 20% interest in Centrahoma for $12.0 million including a capital call.  The purchase increases the Partnership’s ownership to 40%.  Centrahoma owns certain processing plants in the Arkoma basin.  In addition, the Partnership signed agreements to dedicate certain acreage in the Woodford Shale area to Centrahoma through March 1, 2018.  The Partnership’s share of Centrahoma’s income was near zero for both the three and six months ended June 30, 2008.

The Partnership applies the equity method of accounting for its 50% non-operating interest in Starfish Pipeline Company, L.L.C. (“Starfish”).  Differences between the Partnership’s investment and its proportionate share of Starfish’s reported equity are amortized based upon the respective useful lives of the assets to which the differences relate. The Partnership’s share of Starfish’s net income was $0.6 million and $1.7 million for the three months ended June 30, 2008 and 2007, respectively, and $2.1 million and $3.4 million for the six months ended June 30, 2008 and 2007, respectively.  Summarized financial information for 100% of Starfish is as follows (unaudited, in thousands):

	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
Revenues	$	6,656	$	8,558	$	14,377	$	17,070
Operating income	1,329		3,500		4,199		7,553
Net income	1,369		3,455		4,542		7,130

10.Asset Retirement Obligation

A reconciliation of the Partnership’s asset retirement obligation liability as of June 30, 2008 is as follows (in thousands):

Asset retirement obligation as of December 31, 2007	$	1,635
Liabilities incurred	9
Accretion expense	65
Asset retirement obligation as of June 30, 2008	$	1,709

At June 30, 2008 and December 31, 2007, there were no assets legally restricted for purposes of settling asset retirement obligations. The asset retirement obligation has been recorded as part of Other long-term liabilities in the accompanying Condensed Consolidated Balance Sheets.

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11.Impairment of Long-Lived Assets

The Partnership’s policy is to evaluate whether there has been a permanent impairment in the value of long-lived assets when certain events indicate that the remaining balance may not be recoverable.  The Partnership evaluates the carrying value of its property, plant and equipment on at least a segment level and at lower levels where the cash flows for specific assets can be identified.

An analysis completed during the second quarter indicated that the future estimated operating cash flows would be below zero for the Partnership’s gas-gathering assets in Manistee County, Michigan, which are part of the Partnership’s Northeast segment, due to the decision to move the Fisk plant to Pennsylvania and to outsource the gas processing to a third party.  The Partnership used the cash flow method for determining the assets’ fair value and recognized an impairment of long-lived assets of $5.0 million for the three and six months ended June 30, 2008.

12.          Long-Term Debt

Debt is summarized below (in thousands):

	June 30,		December 31,
	2008		2007
Credit Facility
Revolver facility, 7.09% interest at December 31, 2007, retired February 2008	$	—	$	55,500
Revolver facility, 4.75% interest at June 30, 2008, due February 2013	—		—
Senior Notes
Senior Notes, 6.875% interest, net of discount of $10,500 and $0, respectively, due November 2014	214,500		225,000
Senior Notes, 8.5% interest, net of discount of $941 and $2,805, respectively, due July 2016	274,059		272,195
Senior Notes, 8.75% interest, net of discount of $1,242 and $0, respectively, due April 2018	498,758		—
Total long-term debt	$	987,317	$	552,695

Credit Facility

On February 20, 2008, the Partnership entered into a new credit agreement (“Partnership Credit Agreement”). The Partnership Credit Agreement originally provided for a maximum lending limit of $575.0 million through February 2013. The Partnership Credit Agreement included a senior secured revolving facility of $350.0 million (that under certain circumstances could be increased to $550.0 million) and a $225.0 million term loan, both of which could be repaid at any time without penalty. Initial borrowings under the revolving facility portion of Partnership Credit Agreement were used to finance other payments under the Merger and outstanding amounts due on the old partnership credit facility revolver of $67.0 million. The Partnership retired the term loan in April 2008 using a portion of the proceeds from a private placement of Senior Notes completed on April 15.  The Partnership recorded a charge of $4.2 million to write off the deferred financing costs associated with the term loan, which is included in Amortization of deferred financing costs and discount in the accompanying Condensed Consolidated Statements of Operations.  The credit facility is guaranteed and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries. As of June 30, 2008, the Partnership had no borrowings outstanding under the revolving facility and approximately $295.0 million of available borrowings, including outstanding letters of credit of $55.0 million.

The borrowings under the revolving facility of the Partnership Credit Agreement bear interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Partnership Credit Agreement’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Partnership’s Consolidated Funded Debt (as defined in the Partnership Credit Agreement) to Adjusted Consolidated EBITDA (as defined in the Partnership Credit Agreement), ranging from 0.50% to 1.25% for Base Rate loans, and 1.50% to 2.25% for LIBOR loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million. The Partnership will incur a commitment fee on the unused portion of the credit facility at a rate between 30.0 and 50.0 basis points based upon the ratio of consolidated senior debt (as defined in the Partnership Credit Agreement) to consolidated EBITDA (as defined in the Partnership Credit Agreement). As of June 30, 2008, the interest rate for borrowings under the Partnership Credit Agreement would have been LIBOR plus 1.75%, or 4.75%.

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Senior Notes

On April 15, 2008, the Partnership and its wholly-owned subsidiary, MarkWest Energy Finance Corporation (“MarkWest Finance”), completed a private placement of $400 million in aggregate principal amount of 8.75% senior notes due 2018 to qualified institutional buyers under Rule 144A (the “2018  Senior Notes”).  The Partnership received approximately $388.1 million, after deducting initial purchasers’ discounts and the expenses of the offering.  Also, on May 1, 2008, the Partnership completed the placement of an additional $100.0 million pursuant to the indenture to the 2018 Senior Notes (“Indenture”).  The Partnership received approximately $100.4 million, after including initial purchasers’ premium and the estimated expenses of the offering.  The notes issued in this offering and the notes issued on April 15, 2008, will be treated as a single class of debt securities under the Indenture.  The Partnership is utilizing approximately $275.0 million of the net proceeds from the offerings to partially fund its 2008 capital expenditure requirements and the remaining net proceeds were used to repay the $225.0 million term loan portion of the Partnership Credit Agreement entered into on February 20, 2008.

The Partnership filed an exchange offer registration statement, pursuant to the registration rights agreement relating to the 2018 Senior Notes, on May 27, 2008, which was within the time provided for in the subscription agreements.  The exchange offering was initiated on August 5, 2008 and is currently in process.

 In addition to the 2018 Senior Notes issued in April 2008, the Partnership and its wholly-owned subsidiary, MarkWest Finance have two other series of senior notes outstanding as of June 30, 2008; $225.0 million principal due in November 2014 (the “2014 Notes”), and $275.0 million principal due in July 2016 (the “2016 Notes” and all together the “Senior Notes”).  The estimated fair value of the Senior Notes was approximately $998.0 million and $499.8 million at June 30, 2008 and December 31, 2007, respectively, based on quoted market prices.

The Partnership has no independent operating assets or operations.  All wholly-owned subsidiaries guarantee the Senior Notes, jointly and severally and fully and unconditionally.  The notes are senior unsecured obligations equal in right of payment with all of the Partnership’s existing and future senior debt.  These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership’s obligations in respect of the Partnership Credit Agreement.

The indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries.  Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indentures pursuant to Rule 144A and Regulation S under the Securities Act of 1933. If at any time, the 2018 Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Rating Services and no default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate, and the Partnership and its subsidiaries will cease be subject to such covenants.

13.Income Taxes

The Partnership is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Condensed Consolidated Statements of Operations, is includable in the federal income tax returns of each partner. The Partnership is, however, a taxable entity under certain state jurisdictions.  The Corporation is a tax paying entity for both federal and state purposes.

The Partnership and the Corporation account for income taxes under the asset and liability method pursuant to SFAS 109, Accounting for Income Taxes (“SFAS 109”).  Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

The Partnership and the Corporation base the effective tax rate for interim periods on the estimated annual effective tax rate. The Corporation pays tax on its share of the Partnership’s income or loss as a result of its ownership of Class A units.  As a result, the Corporation will have a tax provision related to the ownership of the Class A units without having recognized any book income from those units.

The income tax benefit totaled $31.7 million for the six months ended June 30, 2008, resulting in an effective tax rate of 16.7%. The 2008 estimated annual effective income tax rate varies from the statutory rate mostly due to treatment of the Class A units as discussed above and the write-off of certain deferred tax assets that as an indirect result of the Merger will no longer be realized.

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A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35% to the income before income taxes for the three and six months ended June 30, 2008 is as follows (in thousands):

	Three months ended June 30, 2008
	Corporation			Partnership			Eliminations			Consolidated
Loss before provision for income tax	$	(116,019	)	$	(116,140	)	$	(725	)	$	(232,884	)
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	$	(40,607	)	$	—		$	—		$	(40,607	)
Permanent items	(6		)	—			—			(6		)
State income taxes net of federal benefit	(2,949		)	(762		)	—			(3,711		)
Provision on income from Class A units	(10,793		)	—			—			(10,793		)
Write-off of deferred income tax assets	—			—			—			—
Other	—			—			—			—
Provision for income tax	$	(54,355	)	$	(762	)	$	—		$	(55,117	)
	Six months ended June 30, 2008
	Corporation			Partnership			Eliminations			Consolidated
Loss before provision for income tax	$	(75,627	)	$	(111,239	)	$	(3,424	)	$	(190,290	)
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	$	(26,469	)	$	—		$	—		$	(26,469	)
Permanent items	24			—			—			24
State income taxes net of federal benefit	(1,920		)	(699		)	—			(2,619		)
Provision on income from Class A units	(9,876		)	—			—			(9,876		)
Write-off of deferred income tax assets	7,471			—			—			7,471
Other	(205		)	—			—			(205		)
Provision for income tax	$	(30,975	)	$	(699	)	$	—		$	(31,674	)

14.Equity Offering

On April 14, 2008, the Partnership completed a public offering of 5.75 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $31.15 per common unit.  Net proceeds of approximately $171.4 million were used to pay down borrowings under its revolving credit facility of the Partnership Credit Agreement (see Note 12), and the remainder  is being used to partially fund the Partnership’s 2008 capital expenditure requirements.

15.Incentive Compensation Plans

As of June 30, 2008, the Partnership had four share-based compensation plans which are administered by the Compensation Committee of the General Partner’s board of directors (“Compensation Committee”).  Compensation expense is recognized under SFAS No. 123R, Share-Based Payment (“SFAS 123R”).

	Plan qualification under	Further awards authorized for
Share-based compensation plan	SFAS 123R	issuance under plan
2008 Long-Term Incentive Plan (“2008 LTIP”)	Equity awards	Yes
2006 Hydrocarbon Stock Incentive Plan (“2006 Hydrocarbon Plan”)	Equity awards	No
Long-Term Incentive Plan (“2002 LTIP”)	Liability awards	No
1996 Hydrocarbon Stock Incentive Plan (“1996 Hydrocarbon Plan”)	Equity awards	No

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Compensation Expense

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

	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
Phantom units	$	4,176	$	220	$	6,174	$	1,179
Distribution equivalent rights	140		61		238		125
Restricted stock	—		175		75		373
General partner interests under Participation Plan	274		6,182		5,470		13,773
Total compensation expense	$	4,590	$	6,638	$	11,957	$	15,450

A distribution equivalent right is a right, granted in tandem with a specific phantom unit, to receive an amount in cash equal to, and at the same time as, the cash distributions made by the Partnership with respect to a unit during the period such phantom unit is outstanding. Payment of distribution equivalent rights associated with units that are expected to vest are recorded as capital distributions, however, payments associated with units that are not expected to vest are recorded as compensation expense.

Compensation expense under the share-based compensation plans has been recorded as either Selling, general and administrative expenses or Facility expenses in the accompanying Condensed Consolidated Statements of Operations.

As of June 30, 2008, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan was approximately $23.7 million, with a weighted average remaining vesting period of approximately 1.5 years.  Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP was approximately $3.2 million, with a weighted-average remaining vesting period of approximately 1.3 years.   The actual compensation expense recognized for awards under the 2002 LTIP may differ as they qualify as liability awards under SFAS 123R, which are affected by changes in fair value.

2008 LTIP

The 2008 LTIP was approved by unitholders on February 21, 2008.  The 2008 LTIP provides 2.5 million common units for issuance to the Corporation’s employees and affiliates as share-based payment awards.  The 2008 LTIP was created to attract and retain highly qualified officers, directors, and other key individuals and to motivate them to serve the General Partner, the Partnership and their affiliates and to expend maximum effort to improve the business results and earnings of the Partnership and its affiliates.  Awards authorized under the 2008 LTIP include unrestricted units, restricted units, phantom units, distribution equivalent rights, and performance awards to be granted in any combination.

As of June 30, 2008, 772,500 phantom units have been granted to senior executives and other key employees under the 2008 LTIP in relation to the Merger. The phantom units vest on a time-based and performance-based schedule over a three year period. Forty percent, or 309,000 phantom units, of the total individual grant is based on continuing employment over the three-year vesting period, and sixty percent, or 463,500 phantom units, of the total individual grant contain performance vesting criteria (“performance units”).  As of June 30, 2008, there were 463,500 performance units outstanding, with a grant date fair value of $14.7 million. Vesting of these units occurs if the Partnership achieves established performance goals determined by the Compensation Committee.  In accordance with the provisions of SFAS 123R, management will conduct a quantitative analysis on an ongoing basis to assess the probability of meeting the established performance goals and will record compensation expense as required.  Compensation expense recorded for the performance units expected to vest was approximately $3.4 million and $3.8 million for the three and six months ended June 30, 2008.

2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan

On February 21, 2008, the 25,897 outstanding shares of restricted stock held by 43 employees and directors granted under the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan were converted to 49,354 phantom units, pursuant to the terms of the redemption and merger agreement.  The conversion qualified as a modification in accordance with SFAS 123R, requiring the Partnership to compare the grant date fair value of the original awards with the converted awards.  As a result of the comparison, the Partnership determined that the fair value of the awards had increased by $0.5 million.  Approximately $0.4 million of the fair value was expensed in the first quarter; the remaining $0.1 million will be amortized as compensation expense over the remaining vesting period.  The converted phantom unit awards will remain outstanding under the terms of the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan until their respective settlement dates.

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Summary of Equity Awards

Under SFAS 123R, awards under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan qualify as equity awards. Accordingly, the fair value is measured at the grant date and is based on the market price of the Partnership’s common units.  The associated compensation expense related to service-based awards is recognized over the requisite service period, reduced for an estimate of expected forfeitures.  Compensation expense related to performance units is recognized when probability of vesting is established, as discussed above.  The phantom units, with exception of performance-based awards, generally vest equally over a three year period.  A phantom unit entitles an employee to receive a common unit upon vesting.  The Partnership generally issues new common units upon vesting of phantom units. As part of a net settlement option, employees may elect to surrender a certain number of phantom units, and in exchange, the Partnership will assume the income tax withholding obligations related to the vesting. Phantom units surrendered for the payment of income tax withholdings will again become available for issuance under the plan from which the awards were initially granted, provided that further awards are authorized for issuance under the plan. During the three and six months ended June 30, 2008 and June 30, 2007,  the Partnership was not required to pay any amounts for income tax withholdings related to the vesting of equity awards. The Partnership received no proceeds from the issuance of phantom units, and none of the phantom units that vested were redeemed by the Partnership for cash.

The following is a summary of phantom unit activity under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan:

	Number of Units		Weighted-average Grant-date Fair Value
Unvested at December 31, 2007	—		$	—
Granted (1)	913,185		31.92
Vested	(3,936	)	31.79
Forfeited	—		—
Unvested at June 30, 2008	909,249		31.93

(1) Includes 49,354 restricted shares converted to phantom units pursuant to the terms of the redemption and merger agreement.

	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
Total grant-date fair value of phantom units granted during the period	$	762,445	$	—	$	29,153,383	$	821,840
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	—	$	—	$	125,125	$	147,605

2002 LTIP

As of June 30, 2008, there were 148,531 phantom units outstanding under the 2002 LTIP; no additional awards will be made under the plan.  The phantom units awarded under the 2002 LTIP are classified as liability awards under SFAS 123R.  Accordingly, the fair value of the outstanding awards is re-measured at the end of each reporting period based on the market price of the Partnership’s common units.  The fair value of the phantom units awarded is amortized into earnings as compensation expense over the vesting period, which is generally three years.  A phantom unit entitles an employee to receive a common unit upon vesting, or at the discretion of the Compensation Committee, the cash equivalent to the value of a common unit. The Partnership generally issues new common units upon the vesting of phantom units.  As part of a net settlement option, employees may elect to surrender a certain number of phantom units, and in exchange, the Partnership will assume the income tax withholding obligations related to the vesting.  During the three and six months ended June 30, 2008 and 2007, the Partnership received no proceeds (other than the contributions by the General Partner to maintain its 2% ownership interest prior to the Merger) for issuing phantom units.  None of the phantom units that vested were redeemed by the Partnership for cash, and the Partnership was not required to pay any amounts for income tax withholdings related to the vesting of awards granted under the 2002 LTIP.

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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, 2007	125,250		$	27.42
Granted	78,540		34.00
Vested	(55,047	)	25.89
Forfeited	(212	)	34.00
Unvested at June 30, 2008	148,531		31.46

	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
Total grant-date fair value of phantom units granted during the period	$	—	$	—	$	2,670,360	$	1,486,074
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	—	$	—	$	1,871,598	$	1,261,750

Participation Plan

The interests in the Partnership’s General Partner sold by the Corporation to certain directors and employees were referred to as the Participation Plan.  The Participation Plan was considered a compensatory arrangement and under SFAS 123R, the General Partner interests were classified as liability awards.  As a result, the Corporation was required to calculate the fair value of the General Partner interests at the end of each period.  In conjunction with the Merger, all of the outstanding interests in the General Partner were acquired for a combination of 0.9 million common units with a fair value of approximately $30.1 million and approximately $21.5 million in cash.  As of December 31, 2007, the Participation Plan liability was $47.0 million and is included in Other long-term liabilities in the accompanying Condensed Consolidated Balance Sheets.

Hydrocarbon Stock Options

On or before February 21, 2008, the remaining 51,509 Hydrocarbon stock options outstanding were exercised or deemed exercised with a weighted average exercise price of $7.21.  The following summarizes the impact of the Corporation’s stock options (in thousands):

	Three months ended June 30,		Six months ended June 30,
	2008	2007	2008	2007
Options exercised, cashless	—	—	1	1
Shares issued, cashless	—	—	1	1
Options exercised, cash	—	13	50	13
Shares issued, cash	—	13	50	13

For the six months ended June 30, 2008 and 2007, the Corporation received $0.4 million and $0.1 million, respectively, for the exercise of stock options.  The intrinsic value of the options exercised during the three months ended June 30, 2008 and 2007, was $0.0 and $0.7 million, respectively.  The intrinsic value of the options exercised during the six months ended June 30, 2008 and 2007, was $2.9 million and $0.7 million, respectively.

APIC Pool

At the adoption of SFAS 123R, the Partnership elected to adopt the simplified method to establish the beginning balance of the additional paid-in capital pool (“APIC Pool”) related to the tax effects of employee share-based compensation, and to determine the subsequent impact on the APIC Pool and condensed consolidated statements of cash flows of the tax effects of share-based compensation awards that were outstanding upon adoption of SFAS 123R.  APIC is reported as common units in the accompanying Condensed Consolidated Balance Sheets as a result of the Merger.

SFAS 123R requires that cash flows resulting from tax deductions in excess of the cumulative compensation cost recognized for options exercised be classified as financing cash flows. Previously, all tax benefits from stock options had been reported as an

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operating activity. The company recognized $0.7 million and $0.1 million for the six months ended June 30, 2008 and 2007, respectively, related to excess tax benefits realized from the exercise of stock options.

16.Derivative Financial Instruments

Commodity Instruments

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, futures and option 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 and Condensed Consolidated Statements of Operations.  Accordingly, the volatility in any given period related to unrealized gains or losses can be significant to the overall financial results of the Partnership; however, management ultimately 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 primarily entered into derivative financial instruments relating to the future price of crude oil.  To 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 2011. The Partnership has a committee comprised of the senior management team of the general partner that oversees all of the risk management activity and continually monitors the risk management program and expects to continue to adjust its financial positions as conditions warrant.

To manage its commodity price risk, the Partnership utilizes a combination of fixed-price forward contracts, fixed-for-floating price swaps, options available in the OTC market, and futures contracts.  The Partnership enters into OTC swaps with financial institutions and other energy company counterparties.  Management conducts a standard credit review on counterparties and has agreements containing collateral requirements where deemed necessary.  The Partnership uses standardized agreements that allow for offset of positive and negative exposures.  Due to the timing of purchases and sales, direct exposure to price volatility may result because there is no longer an offsetting purchase or sale that remains exposed to market pricing.  Through marketing and derivative activities, direct price exposure may occur naturally or the Partnership may choose direct exposure when it is favorable as compared to the keep-whole risk.

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) sales volumes are less than expected, requiring market purchases to meet commitments, 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 similarly insulated against unfavorable changes in such prices.

The Partnership values its derivative instruments and estimates fair value as discussed in Note 4.  The impact of the Partnership’s commodity derivative instruments on financial position are summarized below (in thousands):

	June 30, 2008			December 31, 2007
Derivative premiums:
Current asset	$	4,321		$	—
Noncurrent asset	10,743			717
Fair value of derivative instruments:
Current asset	36,389			9,441
Noncurrent asset	40,169			5,414
Current liability	(180,589		)	(77,426		)
Noncurrent liability	(287,660		)	(84,051		)
Net derivative payable	$	(376,627	)	$	(145,905	)

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The Partnership has recorded premium payments relating to certain derivative option contracts. The premiums allowed the Partnership to secure specific pricing on those contracts.  The payment is recorded as an asset and is amortized as a reduction to revenue as the puts expire or are exercised.

The Partnership accounts for the impact of its commodity derivative instruments as either a component of revenue or purchased product costs.  The Partnership has a contract which creates a floor on the frac spread which can be realized on a specific volume purchased.  Gains and losses from this contract are recorded as a component of purchased product costs.  The Partnership also has a contract allowing it to fix a component of the price of electricity at one of its plant locations.  Gains and losses from the contract are recognized as a component of facility expenses.

The impact of the Partnership’s commodity derivative instruments on the results of operations reported in the accompanying Condensed Consolidated Statements of Operations are summarized below (in thousands):

	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008			2007
Derivatives:
Realized (loss) gain — revenue	$	(23,805	)	$	(574	)	$	(42,764	)	$	4,687
Unrealized loss — revenue	(288,786		)	(13,339		)	(316,077		)	(32,509		)
Realized gain (loss) - purchased product costs	8,582			(799		)	8,439			(1,201		)
Unrealized gain (loss) - purchased product costs	38,515			(5,536		)	70,655			(3,507		)
Unrealized gain (loss) — facility expenses	310			(1,029		)	353			(596		)
Total derivative loss	$	(265,184	)	$	(21,277	)	$	(279,394	)	$	(33,126	)

17.Earnings Per Unit

Basic and diluted income per common unit is computed in accordance with SFAS 128, Earnings per Share. Basic income per common unit is computed by dividing net income attributable to common unit holders by the weighted average number of common units outstanding.

All unit and per unit data has been adjusted to reflect the Exchange Ratio to give the effect to the Merger (see Note 3). The following is a reconciliation of the Corporation common stock outstanding during 2007, adjusted to reflect comparable units as a result of the Merger (in thousands):

	Three months ended June 30, 2007		Six months ended June 30, 2007
	Adjusted for Merger	As previously reported	Adjusted for Merger	As previously reported
Weighted average common units and shares of common stock, respectively, outstanding during the period	22,854	11,996	22,844	11,991
Effect of dilutive instruments	—	—	—	—
Weighted average common units and shares of common stock, respectively, outstanding during the period including the effects of dilutive instruments	22,854	11,996	22,844	11,991

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The following table shows the computation of basic and diluted earnings per common unit, for the three and six months ended June 30, 2008 and 2007, and the weighted-average units used to compute diluted net loss per unit.  For the three and six months ended June 30, 2008 and 2007, there is no difference between basic and diluted loss per unit since phantom units and potential common units from the exercises of stock options were anti-dilutive and were, therefore, excluded from the calculation (in thousands, except per unit data):

	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008			2007
Net loss	$	(177,767	)	$	(7,272	)	$	(158,616	)	$	(6,315	)
Weighted average common units outstanding during the period	55,742			22,854			45,326			22,844
Effect of dilutive instruments (1)	—			—			—			—
Weighted average common units outstanding during the period including the effects of dilutive instruments	55,742			22,854			45,326			22,844
Net loss per unit
Basic	$	(3.19	)	$	(0.32	)	$	(3.50	)	$	(0.28	)
Diluted	$	(3.19	)	$	(0.32	)	$	(3.50	)	$	(0.28	)

(1) For the three months ended June 30, 2008 and 2007, 585 units and 110 units, respectively, were excluded from the calculation of diluted units. For the six months ended June 30, 2008 and 2007, 425 units and 110 units, respectively, were excluded from the calculation of diluted units. In accordance with SFAS 128, 464 performance-based units have been excluded from the calculation of diluted units for the three and six months ended June 30, 2008.

18.Distribution to Unitholders and Dividends to Shareholders

On July 24, 2008, the Partnership declared a cash distribution of $0.63 per common unit for the quarter ended June 30, 2008.  The distribution will be paid on August 15, 2008, to unitholders of record as of August 4, 2008.  The ex-dividend date was July 31, 2008.

On April 24, 2008, the Partnership declared a cash distribution of $0.60 per common unit for the quarter ended March 31, 2008.  As a result of the Merger on February 21, 2008, the general partner interests and general partner incentive distribution rights were eliminated.  No further distributions will be made to the general partner or to the general partner incentive distribution rights.  The distribution was paid on May 15, 2008, to unitholders of record as of May 5, 2008.  The ex-dividend date was May 1, 2008.

On January 25, 2008, the Corporation declared a quarterly cash dividend of $0.36 per share of its common stock. Adjusting for the Exchange Ratio of 1.9051, the dividend declared is equivalent to $0.19 per common unit. The dividend was paid on February 15, 2008, to stockholders of record as of the close of business on February 8, 2008.  The ex-dividend date was February 6, 2008.

19.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. 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 Production Company and leased and operated by a subsidiary, MarkWest Energy Appalachia, LLC. The NOPV sets forth six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1,070,000. An administrative hearing on the matter, previously set for the last week of March 2007, was postponed to allow the administrative record

24

to be produced and to allow OPS an opportunity to respond to a motion to dismiss one of the counts of violations, which involves $825,000 of the $1,070,000 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 defenses to the remaining counts and will vigorously defend all applicable assertions of violations at the hearing.

Related to the above referenced 2004 pipeline explosion and fire incident, MarkWest Hydrocarbon and the Partnership have filed an action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed to the U.S. District Court for the District of Colorado, (Civil Action No. 1:05-CV-1948, on October 7, 2005) against their All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain costs related to the pipeline incident. The costs include internal costs incurred for damage to, and loss of use of the pipeline, equipment and products; extra transportation costs incurred for transporting the liquids while the pipeline was out of service; reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). Following initial discovery, MarkWest was granted leave of the Court to amend its complaint to add a bad faith claim and a claim for punitive damages. The Partnership has not provided for a receivable for any of the claims in this action because of the uncertainty as to whether and how much it would ultimately recover under the policies.  The Defendant insurance companies and MarkWest had each filed separate summary judgment motions in the action.  On April 23, 2008, the Court issued an order granting Defendant insurance companies’ motion for summary judgment.  The Partnership believes the Court’s analysis and decision is in error, legally and factually, on numerous grounds and has filed an appeal of this Order to the 10^th Circuit Court of Appeals.

With regard to the Partnership’s Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28^th Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128^th 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, 214^th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), set forth claims for wrongful death, personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area or from products Defendants allegedly manufactured, processed, used, or distributed. The actions have been and are being vigorously defended, and based on initial evaluation and consultations, it appears at this time that these actions should not 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 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.

20.Segment Information

The Partnership classifies its businesses into three reportable segments:  Southwest, Northeast, and Gulf Coast. Operating segments are defined by SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding where to allocate resources and in assessing performance.  The Partnership’s chief operating decision maker is the Chief Executive Officer (“CEO”).  The CEO reviews the Partnership’s discrete financial information on a geographic and operational basis, as the products and services are closely related within each geographic region and business operation.  Accordingly, the CEO makes operating decisions, assesses financial performance and allocates resources on a geographical basis.  The Southwest business unit is engaged in the gathering, processing and transmission of natural gas in Texas, Oklahoma, New Mexico, Louisiana and Mississippi.  The Northeast segment is mainly engaged in the transportation, fractionation, marketing and storage of natural gas liquids in the Appalachian Basin, including the Marcellus Shale, but also includes the Partnership’s operations in Michigan.  The Gulf Coast segment is engaged in the gathering, processing, and fractionation of refinery off-gas in Corpus Christi, Texas.

As a result of the Merger, segment information for the three and six months ended June 30, 2007 has been recast.

Items below Income 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.  The tables below present information about operating income for the reported segments for the three and six months ended June 30, 2008 and 2007.

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Three months ended June 30, 2008 and 2007 (in thousands):

Three months ended June 30, 2008:	Southwest		Northeast		Gulf Coast		Total
Revenue	$	185,812	$	64,893	$	27,453	$	278,158
Operating expenses:
Purchased product costs	109,524		43,749		—		153,273
Facility expenses	14,644		5,207		4,429		24,280
Operating income before items not allocated to segments	$	61,644	$	15,937	$	23,024	$	100,605
Capital Expenditures	$	78,337	$	12,271	$	6,594	$	97,202

Three months ended June 30, 2007:	Southwest		Northeast		Gulf Coast		Total
Revenue	$	125,752	$	55,548	$	17,488	$	198,788
Operating expenses:
Purchased product costs	83,131		41,936		—		125,067
Facility expenses	11,127		3,275		2,984		17,386
Operating income before items not allocated to segments	$	31,494	$	10,337	$	14,504	$	56,335
Capital Expenditures	$	82,662	$	2,567	$	480	$	85,709

The following is a reconciliation of operating income before items not allocated to segments to net income before non-controlling interest and provision for income tax for the three months ended June 30, 2008 and 2007.

	Three months ended June 30,
	2008			2007
Total segment revenue	$	278,158		$	198,788
Derivative loss not allocated to segments	(312,591		)	(13,913		)
Total revenue	$	(34,433	)	$	184,875
Operating income before items not allocated to segments	$	100,605		$	56,335
Derivative loss not allocated to segments	(265,184		)	(21,277		)
Compensation expense included in facility expenses not allocated to segments	(482		)	—
Selling, general and administrative expenses	(16,614		)	(18,811		)
Depreciation	(16,498		)	(9,325		)
Amortization of intangible assets	(10,469		)	(4,168		)
Loss on disposal of property, plant and equipment	—			(9		)
Accretion of asset retirement obligations	(33		)	(28		)
Impairment of long-lived assets	(5,009		)	—
(Loss) income from operations	(213,684		)	2,717
Earnings from unconsolidated affiliates	577			1,656
Interest income	1,662			1,124
Interest expense	(17,450		)	(9,054		)
Amortization of deferred financing costs and discount (a component of interest expense)	(5,164		)	(731		)
Miscellaneous income (expense)	1,175			(317		)
Loss before non-controlling interest in net income of consolidated subsidiary and provision for income tax	$	(232,884	)	$	(4,605	)

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Six months ended June 30, 2008 and 2007 (in thousands):

Six months ended June 30, 2008:	Southwest		Northeast		Gulf Coast		Total
Revenue	$	343,888	$	168,697	$	50,615	$	563,200
Operating expenses:
Purchased product costs	202,162		106,046		—		308,208
Facility expenses	28,519		9,989		8,256		46,764
Operating income before items not allocated to segments	$	113,207	$	52,662	$	42,359	$	208,228
Capital Expenditures	$	129,199	$	17,264	$	25,725	$	172,188

Six months ended June 30, 2007:	Southwest		Northeast		Gulf Coast		Total
Revenue	$	226,357	$	131,704	$	32,347	$	390,408
Operating expenses:
Purchased product costs	150,462		96,662		—		247,124
Facility expenses	20,490		7,309		2,082		29,881
Operating income before items not allocated to segments	$	55,405	$	27,733	$	30,265	$	113,403
Capital Expenditures	$	135,866	$	2,859	$	1,986	$	140,711

The following is a reconciliation of operating income before items not allocated to segments to net income before non-controlling interest and provision for income tax for the six months ended June 30, 2008 and 2007:

	Six months ended June 30,
	2008			2007
Total segment revenue	$	563,200		$	390,408
Derivative loss not allocated to segments	(358,841		)	(27,822		)
Total revenue	$	204,359		$	362,586
Operating income before items not allocated to segments	$	208,228		$	113,403
Derivative loss not allocated to segments	(279,394		)	(33,126		)
Compensation expense included in facility expenses not allocated to segments	(664		)	—
Selling, general and administrative expenses	(39,075		)	(39,381		)
Depreciation	(31,023		)	(17,499		)
Amortization of intangible assets	(17,318		)	(8,336		)
Loss on disposal of property, plant and equipment	(3		)	(154		)
Accretion of asset retirement obligations	(65		)	(55		)
Impairment of long-lived assets	(5,009		)	—
(Loss) income from operations	(164,323		)	14,852
Earnings from unconsolidated affiliates	2,128			3,423
Interest income	2,176			3,520
Interest expense	(28,599		)	(18,468		)
Amortization of deferred financing costs and discount (a component of interest expense)	(6,207		)	(1,451		)
Miscellaneous income (expense)	1,142			(1,067		)
(Loss) income before non-controlling interest in net income of consolidated subsidiary and provision for income tax	$	(193,683	)	$	809

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The tables below present information about segment assets as of June 30, 2008 and December 31, 2007 (in thousands):

As of June 30, 2008:	Southwest		Northeast		Gulf Coast		Total
Total segment assets	$	1,291,516	$	305,273	$	559,688	$	2,156,477
Assets not allocated to segments:
Certain cash and cash equivalents							276,280
Fair value of derivatives							76,558
Derivative premiums							15,064
Investment in unconsolidated affiliates							80,887
Other (1)							24,081
							$	2,629,347

(1) Includes corporate fixed assets and other corporate assets not allocated to segments.

As of December 31, 2007:	Southwest		Northeast		Gulf Coast		Total
Total segment assets	$	780,640	$	186,911	$	392,937	$	1,360,488
Assets not allocated to segments:
Certain cash and cash equivalents							40,623
Fair value of derivatives							14,855
Derivative premiums							717
Investment in unconsolidated affiliates							58,709
Other (1)							49,303
							$	1,524,695

(1) Includes corporate fixed assets, insurance receivable and other corporate assets not allocated to segments.

21.Subsequent Events

Business Combination

On July 31, 2008, the Partnership acquired PQ Gathering Assets, LLC which owns gathering systems and related facilities in the Woodford Shale area of southeastern Oklahoma from PetroQuest Energy, LLC (“PetroQuest”) for approximately $41.3 million.  The transaction will be accounted for as a business combination under SFAS 141, Business Combinations. The purchase price for this acquisition is subject to normal post-closing adjustments. In conjunction with the gathering agreements associated with the acquisition, MarkWest will invest up to an additional $15 million in 2008 and $13 million in 2009 to support the development of PetroQuest’s Woodford Shale and coal bed methane initiatives.

Acquisition of Assets

On August 5, 2008, the Partnership entered into an agreement with Newfield Exploration Mid-Continent Inc. for the acquisition and operation of certain existing gathering and compression assets located in the Texas panhandle for approximately $9.0 million. The transaction will be accounted for as an acquisition of assets. The Partnership expects to invest approximately $95.0 million to $130.0 million over the next three years to support expanding its Western Oklahoma operations.

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. 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.

Merger Summary

On February 21, 2008, the Partnership completed the transactions contemplated by its plan of redemption and merger with the Corporation and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership. Pursuant to this agreement, the Corporation redeemed for cash approximately 3.9 million shares of its common stock, which we refer to as the “redemption,” followed immediately by a merger, pursuant to which all remaining shares of the Corporation common stock were converted into Partnership common units, which we refer to as the “Merger.” As a result of the Merger, the Corporation is a wholly-owned subsidiary of the Partnership. In connection with the redemption and merger, the incentive distribution rights in the Partnership, the 2% economic

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interest in the Partnership held by MarkWest Energy GP, L.L.C. (the “General Partner”) and the Partnership common units owned by the Corporation were exchanged for Partnership Class A units, which are not treated as outstanding units for GAAP purposes. Contemporaneously with the closing of the transactions contemplated by the Merger, the Partnership separately acquired 100% of the Class B membership interests in the General Partner that had been held by current and former management and certain directors of the Corporation and the General Partner for approximately $21.5 million in cash and 0.9 million Partnership common units. The Corporation paid to its stockholders approximately $240.5 million in cash in the redemption and the Partnership issued to the Corporation’s stockholders approximately 15.5 million Partnership common units in the Merger. Please refer to Note 3 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q for further information about the merger and redemption and related subsequent events.

We expect the merger and redemption to offer the following advantages:

·eliminate the incentive distribution rights in the Partnership (see Notes to the Consolidated Financial Statements included in Item 8 of our Form 10-K, as amended, for the year ended December 31, 2007, for information on the incentive distribution rights), which will substantially lower our cost of equity capital;

·enhance the Partnership’s ability to compete for new acquisitions;

·improve the returns to the Partnership unitholders from the Partnership’s expansion projects following the redemption and merger;

·will be accretive to the Partnership’s distributable cash flow per common unit; and

·significantly reduce the costly duplication of services required to maintain two public companies.

The elimination of the incentive distribution rights increases cash available to be distributed to common unitholders. Please refer to “Distributions of Available Cash” in Part II, Item 5 of our Form 10-K, as amended, for the year ended December 31, 2007, for further information. In addition, the Partnership will also be able to distribute available cash from the Corporation after the Corporation pays taxes on its portion of the earnings from its ownership of the Partnership Class A units. Despite the additional interest expense from borrowings needed to complete the merger and redemption, we expect the cash available to distribute to common unitholders to increase in total and on a per common unit basis.

Overview

We are a growth-oriented master limited partnership engaged in the gathering, transportation and processing of natural gas, the transportation, fractionation, marketing and storage of natural gas liquids, and the gathering and transportation of crude oil. We have extensive natural gas gathering, processing and transmission operations in the southwestern and Gulf Coast regions of the United States and are the largest natural gas processor in the Appalachian region. Our primary strategy is to expand our asset base through organic growth projects and selective acquisitions that are accretive to our cash available for distribution.

To better understand our business and the results of operations discussed below, it is important to have an understanding of the following factors:

·management’s use of net operating margin (a non-GAAP measure, see below for reconciliation);

·seasonality;

·the nature of the contracts from which we derive our revenue; and

·our acquisition activity and strategy.

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

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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 usage 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.

The following is a reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure for the three and six months ended June 30, 2008 and 2007 (in thousands):

	Three months ended June 30,					Six months ended June 30,
	2008			2007		2008			2007
Revenue	$	278,158		$	198,788	$	563,200		$	390,408
Purchased product costs	153,273			125,067		308,208			247,124
Net operating margin	124,885			73,721		254,992			143,284
Facility expenses	24,762			17,386		47,428			29,881
Total derivative loss	265,184			21,277		279,394			33,126
Selling, general and administrative expenses	16,614			18,811		39,075			39,381
Depreciation	16,498			9,325		31,023			17,499
Amortization of intangible assets	10,469			4,168		17,318			8,336
Loss on disposal of fixed assets	—			9		3			154
Accretion of asset retirement obligations	33			28		65			55
Impairment of long-lived assets	5,009			—		5,009			—
(Loss) income from operations	$	(213,684	)	$	2,717	$	(164,323	)	$	14,852

Seasonality

Our business is seasonal and sales volumes are affected by factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. In general, we store a portion of the propane that is produced in the summer to be sold in the winter months. We also store pre-purchases in the summer of a portion of the natural gas that we are required to replace during the winter in accordance with our Appalachian keep-whole processing agreements.  As a result of our seasonality, we expect our Northeast segment’s operating income, before items not allocated to segments, to generally be higher in the first quarter and fourth quarter.

Our Contracts

We generate the majority of our revenue and 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 arrangements described below. We provide services under the following different types of arrangements:

·Fee-based arrangements:  Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue we earn from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, our arrangements provide for minimum annual payments or fixed demand charges. If a sustained decline in commodity prices were to result in a decline in volumes, however, our revenues from these arrangements would be reduced.

·Percent-of-proceeds arrangements:  Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, we deliver an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. The percentage of volumes that we retain can be either fixed or variable. Generally, under these types of arrangements our revenues and gross margins increase as natural gas, condensate and NGL prices increase, and our revenues and net operating margins decrease as natural gas, condensate and NGL prices decrease.

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·Percent-of-index arrangements:  Under percent-of-index arrangements, we purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price. With respect to (1) and (3) above, the net operating margins we realize under the arrangements decrease in periods of low natural gas prices because these net operating margins are based on a percentage of the index price. Conversely, our net operating margins increase during periods of high natural gas prices.

·Keep-whole arrangements:  Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Accordingly, under these arrangements our revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decrease as the price of natural gas increases relative to the price of condensate and NGLs.

·Settlement margin:  Typically, we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed-line losses. To the extent our gathering systems are operated more or less efficiently than specified per contract allowance, we will retain the benefit or loss for our own account.

The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common, and other market factors. Any change in mix will influence our long-term financial results.

As of June 30, 2008, our primary exposure to keep-whole contracts was limited to our Appalachian, Western Oklahoma (Arapaho), East Texas (Carthage), and Woodford processing agreements.

·As a result of the Merger with MarkWest Hydrocarbon and the acquisition of its NGL marketing business, our exposure to keep-whole contracts has increased and has resulted in an increase to our exposure to natural gas volatility in Appalachia.

·At the Arapaho plant inlet, natural gas meets the downstream pipeline specification; however, we have the option of extracting NGLs when the processing margin environment is favorable.  Some of our gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low-processing margin environment.  Our keep-whole contract exposure is partially mitigated due to our ability to operate the Arapaho plant in several recovery modes.

·Approximately 9% of the gas processed in East Texas for producers was processed under keep-whole terms for the six months ended June 30, 2008.

·Approximately 50 MMcf/d of the gas in the Woodford system is rich with NGLs processed under keep-whole contracts.  Our keep-whole contract exposure is partially mitigated by our ability to operate in several recovery modes.

·Our keep-whole exposure in all areas was partially offset by the settlement margin related to certain gathering and compression arrangements.  The excess natural gas retained under these arrangements reduced the amount of replacement natural gas purchases required to keep our producers whole on an MMBtu basis, thereby creating a partial natural hedge.  We also have an active commodity risk management program in place to reduce the impacts of changing NGL and natural gas prices and our keep-whole exposure.

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 Part I, Item 3 of this report on Form 10-Q.  For the six months ended June 30, 2008, 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	9	%	33	%	19	%	39	%	100	%
Net operating margin	20	%	34	%	8	%	38	%	100	%

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

(2)Includes settlement margin and other types of arrangements tied to natural gas prices.

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

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While the percentages in the table above accurately reflect the percentages by contract type, we manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment, required levels of operational flexibility and the fact that our hedge plan is implemented on this basis.  When considered on this basis, the calculated percentages for the net operating margin in the table above for percent-of-proceeds, percent-of-index and keep-whole contracts change to 54%, 0% and 26%, respectively.

Our Acquisitions

A significant part of our business strategy includes acquiring additional businesses and assets that allow us to increase distributions to our unitholders. We regularly consider and enter into discussions regarding potential acquisitions. These transactions may be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations.

Since our initial public offering in May 2002, we have completed eleven acquisitions (excluding the Merger) for an aggregate purchase price of approximately $875 million, net of working capital. The acquisitions were individually accounted for as business combinations or equity investments. Summary information regarding each of these acquisitions is presented below (consideration in millions):

Name	Assets	Location	Consideration		Closing Date
PQ Gathering Assets, LLC	Gathering systems	Oklahoma	$	41.3	July 31, 2008
Centrahoma Processing, LLC (1)	Gas processing facility	Oklahoma	23.6		March 1, 2008 and May 9, 2008
Santa Fe	Grimes gathering system	Oklahoma	15.0		December 29, 2006
Javelina (2)	Gas processing and fractionation facility	Corpus Christi, TX	398.8		November 1, 2005
Starfish (3)	Natural gas pipeline, gathering system and dehydration facility	Gulf of Mexico/ Southern Louisiana	41.7		March 31, 2005
East Texas	Gathering system and gas processing assets	East Texas	240.7		July 30, 2004
Hobbs	Natural gas pipeline	New Mexico	2.3		April 1, 2004
Michigan Crude Pipeline	Common carrier crude oil pipeline	Michigan	21.3		December 18, 2003
Western Oklahoma	Gathering system	Western Oklahoma	38.0		December 1, 2003
Lubbock Pipeline	Natural gas pipeline	West Texas	12.2		September 2, 2003
Pinnacle	Natural gas pipelines and gathering systems	East Texas	39.9		March 28, 2003

(1)Represents a 40% non-controlling interest (see Note 9).

(2)Consideration includes $35.5 million in cash acquired.

(3)Represents a 50% non-controlling interest.

We intend to continue pursuing strategic acquisitions of assets and businesses in our existing areas of operation that leverage our current asset base, personnel and customer relationships. We will also seek to selectively acquire assets in regions outside our current areas of operation. We believe the elimination of the incentive distribution rights as a result of the Merger positions us to compete more effectively for acquisitions.

Results of Operations

We reported a net loss of $177.8 million for the three months ended June 30, 2008, compared to net loss of $7.3 million for three months ended June 30, 2007.  We also reported a net loss of $158.6 million for the six months ended June 30, 2008, compared to a net loss of $6.3 million for the six months ended June 30, 2007.

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Contributing factors to the $170.5 million change in net loss for the three months ended June 30, 2008, compared to the same period in 2007 were:

·Derivative losses increased $243.9 million for the three months ended June 30, 2008, compared to the same period in 2007.  The increase is due mainly to the increase in crude oil prices to record high levels during the period. The majority of the increase, approximately $230.0 million, relates to unrealized losses.

·The provision for income tax benefit increased $52.2 million for the three months ended June 30, 2008, compared to the same period in 2007. The increase is due mainly to the significantly higher net loss reported for the second quarter of 2008.   Refer to Note 13 in the accompanying Condensed Consolidated Financial Statements for a further discussion of the significant changes in the provision.

·In the Southwest segment, operating income before items not allocated to segments increased $30.1 million for the three months ended June 30, 2008, compared to the same period in 2007. The increase is due to higher prices in all areas as well as an increase in volumes in East Texas, Woodford, and the Other Southwest operations.

·In the Northeast segment, operating income before items not allocated to segments increased $5.6 million for the three months ended June 30, 2008, compared to the same period in 2007, due mainly to higher prices for NGLs.

·In the Gulf Coast segment, operating income before items not allocated to segments increased $8.5 million for the three months ended June 30, 2008, compared to the same period in 2007. The increase is due primarily to higher prices for NGLs and an increase in the sale of pentanes from zero in 2007 to $2.7 million in 2008.

·Depreciation and amortization increased by $13.5 million for the three months ended June 30, 2008, compared to the same period in 2007. Approximately $9.4 million of the increase is due to the step-up in values for property, plant and equipment and intangible assets related to the Merger.

·Interest expense and amortization of deferred financing costs increased a combined $12.8 million for the three months ended June 30, 2008, relative to the same period in 2007. The increase is related to additional borrowings in 2008 to fund the Merger and to raise capital for future capital projects, and the write off of $4.2 million of deferred finance costs related to the repayment of the term loan portion of the Partnership Credit Agreement.

Cash Distributions

Our quarterly cash distribution of $0.63 per common unit for the quarter ended June 30, 2008 was declared on July 24, 2008.  This distribution is an increase of $0.03 per unit over the first quarter 2008 distribution.

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Operating Data

	Three months ended June 30,				Six months ended June 30,
	2008	2007	% Change		2008	2007	% Change
Southwest
East Texas
Gathering systems throughput (Mcf/d)	431,200	407,000	5.9	%	426,600	404,000	5.6	%
NGL product sales (gallons)	46,871,700	44,486,000	5.4	%	91,355,100	86,274,000	5.9	%
Oklahoma
Foss Lake gathering system throughput (Mcf/d)	95,300	103,700	(8.1	)%	99,600	99,400	0.2	%
Woodford gathering system throughput (Mcf/d)	252,600	102,800	145.7	%	229,100	76,900	197.9	%
Grimes gathering system throughput (Mcf/d)	13,700	11,200	22.3	%	13,400	11,900	12.6	%
Arapaho NGL product sales (gallons)	20,139,800	22,233,000	(9.4	)%	42,160,100	42,758,000	(1.4	)%
Other Southwest
Appleby gathering system throughput (Mcf/d)	62,900	58,000	8.4	%	62,000	53,400	16.1	%
Other gathering systems throughput (Mcf/d)	12,000	8,300	44.6	%	10,700	10,400	2.9	%
Northeast
Appalachia (1)
Natural gas processed for a fee (Mcf/d)	190,300	196,000	(2.9	)%	200,500	199,000	0.8	%
Keep whole sales (gallons)	19,804,500	17,605,000	12.5	%	68,852,400	68,681,000	0.2	%
Percent of proceeds sales (gallons)	10,266,200	10,639,000	(3.5	)%	21,369,800	22,047,000	(3.1	)%
Total NGL product sales (gallons) (2)	30,070,700	28,244,000	6.5	%	90,222,200	90,728,000	(0.6	)%
Michigan
Natural gas processed for a fee (Mcf/d)	2,700	6,100	(55.7	)%	2,700	6,100	(55.7	)%
NGL product sales (gallons)	768,700	1,065,000	(27.8	)%	1,224,000	2,190,000	(44.1	)%
Crude oil transported for a fee (Bbl/d)	13,900	14,200	(2.1	)%	13,800	14,200	(2.8	)%
Gulf Coast
Natural gas processed for a fee (Mcf/d)	122,200	102,000	19.8	%	125,100	115,000	8.8	%
NGLs fractionated for a fee (Bbl/d)	24,400	24,100	1.2	%	24,900	24,500	1.6	%

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

(2) Represents sales at the Siloam fractionator.

Segment Reporting

Segments. As described below, we have three segments based on geographic areas of operations.  For further information, see Note 20 to the Condensed Consolidated Financial Statements, included in Item 1 of this report on Form 10-Q.

Southwest

·East Texas.Our East Texas system 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 and Travis Peak 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 transport volumes for a fee. As part of our 2008 organic growth budget, we began a $28 million expansion of our existing gathering system in East Texas to support volume growth from our producer customers in that area. This expansion is expected to be completed in late 2008. Concurrently, we are investing

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approximately $20 million to expand the processing capacity at our Carthage facility from 200 MMcf/d to 280 MMcf/d. This processing capacity is expected to become operational in the first quarter of 2009.

·Oklahoma. We own the Foss Lake natural gas gathering system and the Arapaho natural gas processing plant that are 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. All of the gathered gas ultimately is compressed and delivered to the processing plant. We also own a natural gas gathering system in the Woodford Shale area in the Arkoma basin of southeastern Oklahoma, and we own the Grimes gathering system, which is located in Roger Mills and Beckham Counties in western Oklahoma. Approximately 80% of our volumes associated with these assets are derived from gathering contracts and approximately 20% are derived from purchase agreements. Approximately $330 million of our 2008 organic growth budget is dedicated to the Oklahoma region. Our expansion projects in this region include the continued development of the Woodford Shale gathering system which includes the acquisition of PQ Gathering Assets, LLC (see Note 21 to the accompanying Condensed Consolidated Financial Statements), the construction of the Arkoma Connector Pipeline to accommodate the rapidly expanding Woodford Shale gas volumes, and the development of a gathering system to support the Hartshorne coal bed methane initiative.   In western Oklahoma, we have recently completed construction of a new processing plant adjacent to our existing Foss Lake processing facilities to accommodate the significant increase in the volume of gas gathered and processed in the Foss Lake system and to support the continued exploration and development of the prolific Anadarko basin.   We have also purchased a gas gathering system in the Texas Panhandle and will invest additional capital to further develop this system and connect it to the expanded Foss Lake processing facilities (see Note 21).

·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 gas produced from fields adjacent to our gathering systems. 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. The New Mexico pipeline facilities and related assets are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We expect to spend approximately $10 million on organic growth projects in these areas of operation in 2008.

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. As part of our organic growth budget for 2008, we estimate we will spend approximately $60 million to significantly expand our gas processing and fractionation capacity in Appalachia. These expansions include replacing our existing Boldman and Cobb processing plants with cryogenic processing facilities and modifying the Kenova processing plant for greater propane recovery to increase production. To support the processing plant expansions, we will increase the capacity at our Siloam fractionation facility by 50 percent, or approximately 300,000 gallons per day. The Kenova upgrade was completed in April 2008. The Siloam facility expansion is expected to be completed in the third quarter of 2008, and the Boldman and Cobb expansions in early 2009.

·Marcellus Shale. In June 2008, we entered into an agreement with a major producer to construct and operate gas gathering pipelines and processing facilities associated with their acreage in the Marcellus Shale area of the Appalachian Basin. In 2008, we expect to invest approximately $75 million to develop our operations in this region.

·Michigan. We own and operate a crude oil pipeline in Michigan, which we refer to as the Michigan Crude Pipeline. The Michigan Crude Pipeline is subject to regulation by the FERC. We also own a natural gas gathering system and the Fisk processing plant in Manistee County, Michigan. In April, the Fisk processing plant was shut down, and is in the process of being moved to the Marcellus Shale area in Pennsylvania as part of the Partnership’s expansion in the Appalachian Basin.

Gulf Coast

·Javelina. We own and operate the Javelina Processing Facility, which is a natural gas processing facility in Corpus Christi, Texas, that treats and processes off-gas from six local refineries. The facility processes approximately 125 to 130 MMcf/d of inlet gas out of its 142 MMcf/d capacity. We have begun construction of a $100 million steam methane

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reformer (“SMR”) at our Javelina plant to meet the needs of our refinery customers for high-purity hydrogen, and expect to commence delivering high-purity hydrogen in early 2010. In 2008, we expect to spend approximately $67 million on the SMR project.

The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by geographic region, for the six months ended June 30, 2008:

	Southwest		Northeast		Gulf Coast		Total
Revenue	61	%	30	%	9	%	100	%
Net operating margin	56	%	24	%	20	%	100	%

Equity investments in unconsolidated affiliates

Starfish. We own a 50% non-operating membership interest in Starfish Pipeline Company, LLC, (“Starfish”), whose assets are located in the Gulf of Mexico and southwestern Louisiana. The Starfish interest is part of a joint venture with Enbridge Offshore Pipelines L.L.C., which is accounted for using the equity method; the financial results for Starfish are included in Earnings from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations and are not included in the Gulf Coast segment results.

Centrahoma.  On March 1, 2008, we acquired a 20% interest in Centrahoma Processing, LLC (“Centrahoma”), and on May 9, 2008, we exercised our right to acquire an additional 20%. Centrahoma assets are located in the Woodford Shale area and are operated by a third party. The Partnership’s investment in Centrahoma is accounted for under the equity method.

Three months ended June 30, 2008, compared to three months ended June 30, 2007

Items below Income 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.  The tables below present information about operating income for the reported segments for the three months ended June 30, 2008 and 2007.

Southwest

	Three months ended June 30,
	2008			2007
	(in thousands)
Revenue	$		185,812	$		125,752
Operating expenses:
Purchased product costs	109,524			83,131
Facility expenses	14,644			11,127
Total operating expenses before items not allocated to segments	124,168			94,258
Operating income before items not allocated to segments	$	61,644		$	31,494

Revenue.  Revenue increased $60.1 million, or 48%, during the three months ended June 30, 2008, relative to the same period in 2007.  The increase is due to a $29.4 million increase in East Texas from the sale of greater NGL volumes at higher prices and increased condensate sales. Additionally, continued expansion in the Woodford gathering system and the start of gas processing operations in this area increased revenue approximately $14.5 million.  Revenues from Other Southwest areas increased approximately $16.4 million due to higher prices and increased volumes of approximately 8,600 Mcf/d in the gathering systems. Revenues from the Foss Lake region remained flat in 2008 compared to 2007 as the impact of higher prices was offset by lower volumes.

Purchased Product Costs.  Purchased product costs increased $26.4 million, or 32%, during the three months ended June 30, 2008, relative to the same period in 2007. The increase is related mainly to increased purchased product costs in East Texas from percent-of-proceeds arrangements.  Additional increases are related to the increased volumes and higher prices in the Other Southwest areas.

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Facility Expenses.  Facility expenses increased $3.5 million, or 32%, during the three months ended June 30, 2008, relative to the same period in 2007. The increase was primarily due to the increased operations for the Woodford gathering system and expanded operations in most areas of the Southwest segment.

Northeast

	Three months ended June 30,
	2008		2007
	(in thousands)
Revenue	$	64,893	$	55,548
Operating expenses:
Purchased product costs	43,749		41,936
Facility expenses	5,207		3,275
Total operating expenses before items not allocated to segments	48,956		45,211
Operating income before items not allocated to segments	$	15,937	$	10,337

Revenue. Revenue increased $9.3 million, or 17%, during the three months ended June 30, 2008, relative to the same period in 2007.  The increase is mainly due to higher prices partially offset by lower volumes.

Purchased Product Costs. Purchased product costs increased by $1.8 million, or 4%, during the three months ended June 30, 2008, relative to the same period in 2007.  The increase is mainly due higher prices for natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area, partially offset by a $1.0 million decrease in trucking expenses. Trucking expenses associated with the Appalachia Liquids Pipeline System decreased due to a change in contractual terms with a producer.

Facility Expenses.  Facility expenses increased $1.9 million, or 59%, during the three months ended June 30, 2008, relative to the same period in 2007.   The increase was primarily due to increased plant fuel gas costs, repairs and maintenance, and increased labor and benefits expense.

Gulf Coast

	Three months ended June 30,
	2008		2007
	(in thousands)
Revenue	$	27,453	$	17,488
Operating expenses:
Facility expenses	4,429		2,984
Total operating expenses before items not allocated to segments	4,429		2,984
Operating income before items not allocated to segments	$	23,024	$	14,504

Revenue.  Revenue is generated under percent-of-proceeds arrangements and is generally reported net of purchased product costs. We gather and process natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds based on an index price.

Revenue increased $10.0 million, or 57%, during the three months ended June 30, 2008, relative to the same period in 2007. The increase is due mainly to higher pricing and higher inlet volumes partially offset by a slightly lower percent-of-proceeds (“POP”) received.  Effective March 1, 2008, a significant contract changed from a fixed POP to variable POP, resulting in a lower POP received.  In addition, the sale of pentanes generated $2.7 million of revenue in the quarter, compared to no sales of pentanes in the second quarter of 2007.  The pentanes are stored as a result of their seasonality and the revenue generated from the sale will not be recurring.

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Facility Expenses.  Facilities expenses increased $1.4 million, or 48%, during the three months ended June 30, 2008, relative to the same period in 2007.  The increase is due to increased energy expenses related to a new contract in March 2008 whereby the Partnership shares the cost of electricity.  In 2007 these expenses were fully reimbursed by the customer.

Reconciliation of Segment Operating Income to Consolidated Net Income Before Non-Controlling Interest and

Provision for Income Tax

The following table provides a reconciliation of segment income to our consolidated net income before non-controlling interest and provision for income tax for the three months ended June 30, 2008 and 2007. The ensuing items listed below the 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 June 30,
	2008			2007
	(in thousands)
Total segment revenue	$	278,158		$	198,788
Derivative loss not allocated to segments	(312,591		)	(13,913		)
Total revenue	$	(34,433	)	$	184,875
Operating income before items not allocated to segments	$	100,605		$	56,335
Derivative loss not allocated to segments	(265,184		)	(21,277		)
Compensation expense included in facility expenses not allocated to segments	(482		)	—
Selling, general and administrative expenses	(16,614		)	(18,811		)
Depreciation	(16,498		)	(9,325		)
Amortization of intangible assets	(10,469		)	(4,168		)
Loss on disposal of property, plant and equipment	—			(9		)
Accretion of asset retirement obligations	(33		)	(28		)
Impairment of long-lived assets	(5,009		)	—
(Loss) income from operations	(213,684		)	2,717
Earnings from unconsolidated affiliates	577			1,656
Interest income	1,662			1,124
Interest expense	(17,450		)	(9,054		)
Amortization of deferred financing costs and discount (a component of interest expense)	(5,164		)	(731		)
Miscellaneous income (expense)	1,175			(317		)
Loss before non-controlling interest in net income of consolidated subsidiary and provision for income tax	$	(232,884	)	$	(4,605	)

Derivative Loss. Loss from derivative instruments increased $243.9 million, during the three months ended June 30, 2008, relative to the same period in 2007.  Mark-to-market adjustments resulted in a $230.1 million increase in unrealized loss.  Settlements of our derivative instruments resulted in a $13.9 million increase in realized losses, when comparing 2008 to 2007 results.  The increased derivative loss is primarily attributable to historically high crude oil prices.

Selling, General and Administrative Expenses.  Selling, general and administrative expenses decreased $2.2 million, or 12%, during the three months ended June 30, 2008, relative to the same period in 2007.  Compensation expense related to the Participation Plan decreased by $5.9 million.  Additionally, professional services fees and office expenses decreased by approximately $1.0 million due mainly to Merger expenses incurred in 2007 that did not recur in 2008. These decreases were partially offset by $3.3 million of additional compensation expense related to phantom unit awards, and a $1.3 million increase in labor and benefits related to a higher wage base and larger employee group in 2008.

Depreciation and Amortization of Intangible Assets.  Depreciation and amortization increased $13.5 million, or 100%, during the three months ended June 30, 2008, relative to the same period in 2007, of which approximately $9.4 million is due to the step-up in

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values for property, plant and equipment and intangible assets as a result of the Merger.  The remainder is due to additional projects completed throughout 2007 and the first half of 2008.

Impairment of Long-Lived Assets.  During the quarter ended June 30, 2008, we recognized an impairment charge of $5.0 million related to certain gas-gathering assets in the Northeast segment. Refer to Note 11 in the accompanying Notes to the Condensed Consolidated Financial Statements for further discussion.

Earnings from Unconsolidated Affiliates.  Earnings from unconsolidated affiliates are primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines L.L.C.  We account for our 50% interest using the equity method, and the financial results for Starfish are included as earnings from unconsolidated affiliates.  During the three months ended June 30, 2008, our earnings from unconsolidated affiliates decreased $1.1 million, or 65%, relative to the same period in 2007.

Interest Income.  Interest income increased $0.5 million, or 48%, during the three months ended June 30, 2008, relative to the same period in 2007, due to interest earnings on additional money market investments resulting from the cash raised in the debt and equity offerings in April 2008.

Interest Expense. Interest expense increased $8.4 million, or 93%, during the three months ended June 30, 2008, relative to the same period in 2007, primarily due to increased borrowings in 2008 to fund the Merger and to raise capital for organic growth projects.

Miscellaneous Income (Expense). Miscellaneous income was approximately $1.2 million for the three months ended June 30, 2008, compared to miscellaneous expense of $0.3 million during the same period in 200. The change is primarily related to the settlement of insurance claims for both business interruption and property damage to Starfish resulting from Hurricanes Rita and Katrina in 2005.  As part of the settlement in April 2008, the partnership received $1.8 million of proceeds in excess of the amount that had previously been recorded.

Non-controlling Interest in Net Income of Consolidated Subsidiary.  The non-controlling interest in net income of consolidated subsidiary decreased $5.6 million during the three months ended June 30, 2008, relative to the same period in 2007. As a result of the merger, there was no longer a non-controlling interest in the Partnership during the second quarter.

Provision for Income Tax.  The provision for income tax benefit increased $52.2 million, during the three months ended June 30, 2008, relative to the same period in 2007.  Refer to Note 13 in the accompanying Condensed Consolidated Financial Statements for a discussion of the significant changes in the provision.

Six months ended June 30, 2008, compared to six months ended June 30, 2007

The tables below present information about operating income for the reported segments for the six months ended June 30, 2008 and 2007.

Southwest

	Six months ended June 30,
	2008		2007
	(in thousands)
Revenue	$	343,888	$	226,357
Operating expenses:
Purchased product costs	202,162		150,462
Facility expenses	28,519		20,490
Total operating expenses before items not allocated to segments	230,681		170,952
Operating income before items not allocated to segments	$	113,207	$	55,405

Revenue.  Revenue increased $117.5 million, or 52%, during the six months ended June 30, 2008, relative to the same period in 2007.  Revenues in East Texas and Western Oklahoma increased by $58.0 million and $8.5 million, respectively, due to the sale of additional NGL volumes at higher prices and increased condensate sales. Additionally, continued expansion in the Woodford gathering system and the launch of the Scipio gathering system increased revenue approximately $28.1 million.  Revenues from Other

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Southwest areas increased approximately $23.0 million due to higher prices and increased volumes in the gathering systems of approximately 8,900 Mcf/d.

Purchased Product Costs.  Purchased product costs increased $51.7 million, or 34%, during the six months ended June 30, 2008, relative to the same period in 2007. The increase is related mainly to higher purchased product costs in East Texas resulting from the higher revenues attributable to percent-of-proceeds arrangements.  Additional increases are related to the increased volumes and higher prices in the Other Southwest areas. NGL and gas purchases associated with the Woodford expansion also contributed to the increase.

Facility Expenses.  Facility expenses increased $8.0 million, or 39%, during the six months ended June 30, 2008, relative to the same period in 2007. The increase was primarily due to the increased operations for the Woodford gathering system and expanded operations in most areas of the Southwest segment.

Northeast

	Six months ended June 30,
	2008		2007
	(in thousands)
Revenue	$	168,697	$	131,704
Operating expenses:
Purchased product costs	106,046		96,662
Facility expenses	9,989		7,309
Total operating expenses before items not allocated to segments	116,035		103,971
Operating income before items not allocated to segments	$	52,662	$	27,733

Revenue. Revenue increased $37.0 million, or 28%, during the six months ended June 30, 2008, relative to the same period in 2007.  The increase is mainly due to higher prices and slightly higher volumes.

Purchased Product Costs. Purchased product costs increased by $9.4 million, or 10%, during the six months ended June 30, 2008, relative to the same period in 2007.  The increase is mainly due higher prices for natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area. This increase is partially offset by a $1.8 million decrease in trucking expenses. Trucking expenses associated with the Appalachia Liquids Pipeline System decreased due to a change in contractual terms with a producer.

Facility Expenses.  Facility expenses increased $2.7 million, or 37%, during the six months ended June 30, 2008, relative to the same period in 2007.   The increase was primarily due to increased plant fuel gas costs, repairs and maintenance and increased labor and benefits expense.

Gulf Coast

	Six months ended June 30,
	2008		2007
	(in thousands)
Revenue	$	50,615	$	32,347
Operating expenses:
Facility expenses	8,256		2,082
Total operating expenses before items not allocated to segments	8,256		2,082
Operating income before items not allocated to segments	$	42,359	$	30,265

Revenue.  Revenue increased $18.3 million, or 56%, during the six months ended June 30, 2008, relative to the same period in 2007.  The increase is due mainly to higher pricing and inlet volumes partially offset by a slightly lower POP received.  Effective March 1, 2008, a significant contract changed from a fixed POP to variable POP, resulting in a lower POP received.  In addition, the

40

sale of pentanes generated $3.2 million of revenue during the six months ended June 30, 2008, compared to no sales of pentanes during the same period in 2007.  The pentanes are stored as a result of their seasonality and the revenue generated from the sale will not be recurring.

Facility Expenses.  Facilities expenses increased $6.2 million, or 297%, during the six months ended June 30, 2008, relative to the same period in 2007.  The increase is for the most part attributable to a utility refund of $3.6 million from a rate case concluded in the first quarter of 2007.  Excluding the refund, operating expenses were $2.6 million higher for the six months ended June 30, 2008 due mainly to increased energy expenses related to a new contract in March 2008 whereby the Partnership shares the cost of electricity.  In 2007 these expenses were reimbursed by the customer.

Reconciliation of Segment Operating Income to Consolidated Net Income Before Non-Controlling Interest and

Provision for Income Tax

The following table provides a reconciliation of segment income to our consolidated net income before non-controlling interest and provision for income tax for the six months ended June 30, 2008 and 2007.  The ensuing items listed below the 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.

	Six months ended June 30,
	2008			2007
	(in thousands)
Total segment revenue	$	563,200		$	390,408
Derivative loss not allocated to segments	(358,841		)	(27,822		)
Total revenue	$	204,359		$	362,586
Operating income before items not allocated to segments	$	208,228		$	113,403
Derivative loss not allocated to segments	(279,394		)	(33,126		)
Compensation expense included in facility expenses not allocated to segments	(664		)	—
Selling, general and administrative expenses	(39,075		)	(39,381		)
Depreciation	(31,023		)	(17,499		)
Amortization of intangible assets	(17,318		)	(8,336		)
Loss on disposal of property, plant and equipment	(3		)	(154		)
Accretion of asset retirement obligations	(65		)	(55		)
Impairment of long-lived assets	(5,009		)	—
(Loss) income from operations	(164,323		)	14,852
Earnings from unconsolidated affiliates	2,128			3,423
Interest income	2,176			3,520
Interest expense	(28,599		)	(18,468		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(6,207		)	(1,451		)
Miscellaneous income (expense)	1,142			(1,067		)
(Loss) income before non-controlling interest in net income of consolidated subsidiary and provision for income tax	$	(193,683	)	$	809

Derivative Loss. Loss from derivative instruments increased $246.3 million during the six months ended June 30, 2008, relative to the same period in 2007.  Mark-to-market adjustments resulted in a $208.5 million increase in unrealized loss.  Settlements of our derivative instruments resulted in a $37.8 million increase in realized losses, when comparing 2008 to 2007 results.  The increased derivative loss is primarily attributable to historically high crude oil prices.

Selling, General and Administrative Expenses.  Selling, general and administrative expenses decreased $0.3 million, or 1%, during the six months ended June 30, 2008, relative to the same period in 2007.  Compensation expenses related to phantom unit awards increased by approximately $4.5 million.  Professional services fees and office-related expenses increased by $1.8 million of which $1.1

41

million is Merger related, and labor and benefits expense increased by of $1.7 million related to a higher wage and benefit base in 2008.  In addition, taxes, other than income tax, and insurance costs increased.  Increases in costs were offset by a decrease in compensation expense related to the Participation Plan of $8.3 million.

Depreciation and Amortization of Intangible Assets.  Depreciation and amortization increased $22.5 million, or 87%, during the six months ended June 30, 2008, relative to the same period in 2007, of which approximately $14.0 million is due to the step-up in values for property, plant and equipment and intangible assets as a result of the Merger.  The remainder is due to additional projects completed throughout 2007 and the first half of 2008.

Impairment of Long-Lived Assets.  During the quarter ended June 30, 2008, we recognized an impairment charge of $5.0 million related to certain gas-gathering assets in the Northeast segment. Refer to Note 11 in the accompanying Notes to the Condensed Consolidated Financial Statements for further discussion.

Earnings from Unconsolidated Affiliates.  Earnings from unconsolidated affiliates are primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines L.L.C.  We account for our 50% interest using the equity method, and the financial results for Starfish are included as earnings from unconsolidated affiliates.  During the six months ended June 30, 2008, our earnings from unconsolidated affiliates decreased $1.3 million, or 38%, relative to the same period in 2007.

Interest Income.  Interest income decreased $1.3 million, or 38%, during the six months ended June 30, 2008, relative to the same period in 2007, mainly due to proceeds received in the first quarter of 2007 from a rate case in our Gulf Coast segment. This decrease was partially offset by interest earnings on additional money market investments resulting from the cash raised in the debt and equity offerings in April 2008.

Interest Expense. Interest expense increased $10.1 million, or 55%, during the six months ended June 30, 2008, relative to the same period in 2007, primarily due to increased borrowings in 2008 to fund the Merger and to raise capital for future acquisitions and growth projects.

Miscellaneous Income (Expense). Miscellaneous income was approximately $1.2 million during the six months ended June 30, 2008, compared to miscellaneous expense of approximately $1.1 million during the same period in 2007. The change is primarily related to the settlement of insurance claims for both business interruption and property damage to Starfish resulting from Hurricanes Rita and Katrina in 2005.  As part of the settlement in April 2008, the partnership received $1.8 million of proceeds in excess of the amount that had previously been recorded.

Non-controlling Interest in Net Income of Consolidated Subsidiary.  The non-controlling interest in net income of consolidated subsidiary increased $12.9 million, during the six months ended June 30, 2008, relative to the same period in 2007, partially as a result of the Merger on February 21, 2008, with the remainder being changes in operational results of the Partnership prior to the Merger.

Provision for Income Tax.  The provision for income tax benefit increased $29.3 million during the six months ended June 30, 2008, relative to the same period in 2007.  Refer to Note 13 in the accompanying Condensed Consolidated Financial Statements for a discussion of the significant changes in the provision.

Liquidity and Capital Resources

Our primary sources of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions), are cash flows generated by our operations and our access to equity and debt markets.  The equity and debt markets, public and private (retail and institutional) have been our principal source of capital used to finance a significant amount of our growth, including acquisitions.

Our primary strategy is to expand our asset base through organic growth projects and selective acquisitions that are accretive to our cash available for distribution. In 2007, we spent approximately $309 million on internal development and expansion opportunities. In 2008, we have completed two third-party acquisitions and the Merger with MarkWest Hydrocarbon. For 2008, we estimate we will spend between $500 million and $550 million to fund identified organic growth and expansion projects that have been approved by our board of directors, which includes the acquisition of PQ Gathering Assets, LLC and the expansion of our Western Oklahoma operations. (see Note 21 to the accompanying Condensed Consolidated Financials Statements).  As of June 30, 2008, we have spent $195.8 million of our budget, including $23.6 million for our investment in Centrahoma, and $2.4 million for maintenance capital.  Growth capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets, or facilitate an increase in volumes within our operations, whether through construction or acquisition.  Maintenance capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

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On February 20, 2008, we entered into the Partnership Credit Agreement consisting of a $350.0 million revolving credit facility and a $225.0 million term loan, each of which has a five-year term. In connection with the Merger, we initially borrowed the entire $225.0 million under the term loan. In addition, we borrowed $84.0 million under the revolving credit facility in connection with the refinancing of our prior credit facility.  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 August 4, 2008 approximately 90% of our derivative positions, measured volumetrically, are with members of the participating bank group. 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.

On April 14, 2008, we completed a public placement of 5.75 million newly issued common units, including overallotments, representing limited partner interests at a purchase price of $31.15 per common unit.  The net proceeds were approximately $171.4 million.

On April 15, 2008, we completed a private placement of $400.0 million in aggregate principal amount of 8.75% senior notes due 2018 to qualified institutional buyers under Rule 144A (the “2018 Notes”).  We received net proceeds of approximately $388.1 million, after deducting initial purchasers’ discounts and the estimated expenses of the offering.   On May 1, 2008, we completed a follow-on offering of $100.0 million under the indenture of the 2018 Notes. We received net proceeds of $100.4 million, after including initial purchasers’ premium and the estimated expenses of the offering. The notes issued on April 15, 2008, and the notes issued on May 1, 2008, will be treated as a single class of debt securities under the indenture.  The indenture covering the 2018 Notes limits our activity and our restricted subsidiaries as discussed further in Note 12 to the accompanying Condensed Consolidated Financial Statements.

The net proceeds of the debt and equity offerings were used to pay down the $225.0 million term loan and $83.0 million outstanding under the revolving credit facility.  The remaining net proceeds will be used to fund our capital expenditure requirements.  Payment of the $225.0 million term loan permanently reduced the borrowing capacity of the Partnership Credit Agreement to the $350.0 million revolving credit facility.  Under the provisions of the Partnership Credit Agreement we are subject to a number of restrictions and covenants as defined by the agreement.  These covenants are used to calculate the available borrowing capacity on a quarterly basis.  As of August 4, 2008, we had no borrowings outstanding under the revolving credit facility and had approximately $290.0 million available for borrowing, with $60.0 million of letters of credit outstanding.  As of August 4, 2008, we had approximately $235.3 million invested in money market funds.

In addition to the 2018 Senior Notes issued in April 2008, the Partnership, in conjunction with MarkWest Energy Finance Corporation, had two other series of senior notes outstanding as of June 30, 2008; $225.0 million aggregate principal maturing in November 2014, and $275.0 million aggregate principal due in July 2016. For further discussion of the Senior Notes see Note 12 to the accompanying Condensed Consolidated Financial Statements.

Our ability to pay distributions to our unitholders and to fund planned capital expenditures and 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.

Cash Flow

The following table summarizes cash inflows (outflows) for the six months ended June 30, 2008 and 2007 (in thousands):

	Six months ended June 30,
	2008			2007
Net cash flows provided by operating activities	$	163,958		$	32,364
Net cash flows used in investing activities	(459,453		)	(140,727		)
Net cash flows provided by financing activities	536,113			99,428

Net cash provided by operating activities increased $131.6 million during the six months ended June 30, 2008, compared to the corresponding period in 2007.  The change resulted from an increase in operating income, excluding derivative gains and losses, in all reportable segments, and return of margin deposits held as of December 31, 2007, offset by premiums paid for derivative instruments.

Net cash used in investing activities increased $318.7 million during the six months ended June 30, 2008, compared to the corresponding period in 2007.  This increase was primarily due to cash paid as consideration in the Merger of $269.6 million, including $21.5 million paid to acquire the General Partnership’s minority interest. Additional increases were due to increased capital expenditures primarily from our organic growth projects, where we spent approximately $193.5 million of expansion capital, including equity investments.

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Net cash provided by financing activities increased $436.7 million during the six months ended June 30, 2008, compared to the corresponding period in 2007.  The increase was primarily due to $443.2 million of net borrowings on long-term debt and $171.4 million in proceeds from a public equity offering. The cash provided by these financing activities was used primarily to fund the cost of the Merger and to raise capital for future projects.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of June 30, 2008, the Partnership’s purchase obligations for 2008 were $127.8 million compared to $88.1 million as of December 31, 2007. Other than this increase in purchase obligations and the issuance of additional long-term debt (as discussed further in Note 12 of the accompanying Notes to the Condensed Consolidated Financial Statements) there were no material changes to our contractual obligations.

Matters Impacting Future Results

The Partnership completed the Merger with the Corporation and entered into the Partnership Credit Agreement  on February 21, 2008, as discussed further in Note 12 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q. The Merger is considered a downstream merger whereby the Corporation is viewed as the surviving consolidated entity for accounting purposes rather than the Partnership, which is the surviving consolidated entity for legal purposes. As such, the Merger was accounted for in the Corporation’s consolidated financial statements as an acquisition of non-controlling interest using the purchase method of accounting. Under this accounting method, the Partnership’s accounts, including goodwill, were adjusted to proportionately step up the book value of certain assets and liabilities.

As discussed in Note 15 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q, the Partnership acquired all of the outstanding interests in the General Partner. In the future, our results will not include compensation for the general partner interests under the Participation Plan. For the three months ended June 30, 2008 and 2007, our results included compensation expense of $0.3 million and $6.2 million, respectively, related to the Participation Plan.  For the six months ended June 30, 2008 and 2007, our results included compensation expense of $5.5 million and $13.8 million, respectively, related to the Participation Plan.

The 2008 LTIP reserves 2.5 million common units for issuance in the future. As discussed further in Note 15 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q, on February 21, 2008, 765,000 phantom units were granted to senior executives and other key employees under the 2008 LTIP.  An additional 7,500 phantom units were granted during the quarter ended June 30, 2008, under the same arrangement.  The amount of compensation expense related to these grants will range from $9.8 million to $24.6 million. Forty percent (40%) of the total individual grant is based on continuing employment over the three-year vesting period and this represents the minimum in the range. Sixty percent (60%) of the total individual grant is performance-based and is conditional upon the achievement of designated annual financial performance goals established by the Board of Directors. The maximum of the range assumes such conditions will be achieved. The timing of this expense cannot be estimated.

 On March 1, 2008, we acquired a 20% interest in Centrahoma Processing, LLC (“Centrahoma”) for $11.6 million, which is accounted for under the equity method.  On May 9, 2008, the Partnership acquired an additional 20% interest in Centrahoma for $12.0 million including a capital call, which brings the Partnership’s total ownership interest to 40%.  Centrahoma owns certain processing plants in the Arkoma basin. In addition, we signed agreements to dedicate certain acreage in the Woodford Shale play to Centrahoma through March 1, 2018.  Our share of Centrahoma’s income was near zero for both the three and six months ended June 30, 2008.

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Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements and accompanying notes. Actual results could differ from those estimates. Consistent with the Critical Accounting Policies disclosed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our 2007 Annual Report on Form 10-K, as amended, significant estimates using management judgment are made for the following areas:

·Intangible Assets

·Impairment of Long-Lived Assets

·Investment in Starfish

·Derivative Instruments

·Revenue Recognition

·Incentive Compensation Plans

There have not been any material changes during the six months ended June 30, 2008, to the methodology applied by management for critical accounting policies previously disclosed except for the following: fair value measurement, purchase price allocation and the investment in Centrahoma as discussed below.

Fair Value Measurement

We adopted the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standard (“SFAS”) No. 157, Fair Value Measurements (“SFAS 157”), effective January 1, 2008, with portions deferred by the FASB as discussed in Note 4 to the accompanying Notes to the Condensed Consolidated Financial Statements.  SFAS 157 defines fair value, establishes a framework for measuring fair value, establishes a three-level valuation hierarchy, and expands the disclosures about fair value measurements.

Our accounting policy requires us to determine the categorization of assets or liabilities based upon the lowest level of input that is significant to the fair value measurement.  The Partnership’s derivative positions are valued using corroborated market data and internally developed models when observable market data is not available.  Commodity transactions based on crude oil and natural gas are considered Level 2 transactions as the pricing methodology include quoted prices for similar assets and liabilities and the Partnership can determine the prices are observable and do not contain Level 3 inputs that are significant to the measurement.  Natural gas liquid positions have significant unobservable market parameters and are normally traded less actively or have trade activity that is one way and therefore, are classified within Level 3 of the valuation hierarchy.

The methods 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 we believe our 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.  For further discussion on SFAS 157 and the impact on our financial statements, see Note 4 to the accompanying Notes to the Condensed Consolidated Financial Statements.

Purchase Price Allocation

As discussed in Note 3 to the accompanying Condensed Consolidated Financial Statements, the Merger was accounted for as an acquisition of non-controlling interest using the purchase method of accounting.  Under the purchase method of accounting, the total purchase price was allocated to the minority interest in the net assets of the Partnership based on the estimated fair values of its assets and liabilities as of the Merger date.

Significant fair value estimates were required for the following assets and liabilities:

·Property, plant, and equipment — The fair value estimates for property, plant and equipment were based primarily on the cost approach which considers both historical cost and replacement cost. Additionally, the Partnership estimated the remaining useful lives of the property, plant and equipment to ensure that the useful lives used for depreciation subsequent to the Merger are reasonable and consistent with the Partnership’s accounting policy.

·Intangible assets — The fair value estimates for customer relationships were based on a version of the income approach. The income approach involves estimating future cash flows from existing customer relationships and making provisions for a fair return on other recognized contributory assets. Key assumptions in the valuation include contract renewals, economic incentives to retain customers, historic volumes, current and future capacity in the gathering

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system, pricing volatility and the discount rate. The estimated useful life of the intangible assets was determined by assessing the estimated useful life of the other assets to which the contracts and relationships relate, likelihood of renewals, projected reserves, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

·Long-term debt — The fair value of the Partnership’s Senior Notes was estimated using a high yield market price at which our debt was trading as of the acquisition date.

·Deferred finance costs — The deferred finance costs of the Partnership have no fair market value as of the acquisition date. Therefore 85.7% of these costs are written-off under the purchase method of accounting.

The remaining purchase price in excess of the fair values of the assets and liabilities acquired was recorded as goodwill.

Management considers the underlying assumptions and estimates utilized in the fair market value analyses and determination of useful lives for tangible and intangible assets to be reasonable based on the current economic and market conditions. However, these estimates are inherently subject to economic and competitive uncertainties that are beyond the Partnership’s control.  The occurrence of certain events such as unfavorable regulatory actions, significant adverse changes in the legal factors or in the business climate, unexpected competition, loss of key personnel, significant commodity price decreases, significant loss of producers or a significant decrease in the expected output from producers could require the Partnership to evaluate the recoverability of the tangible and intangible assets, including goodwill. This evaluation could result in impairment charges in the future which could significantly impact reported earnings in the periods such charges occur.

Investment in Centrahoma Processing, LLC

On March 1, 2008, the Partnership acquired a 20% interest in Centrahoma and on May 9, 2008, the Partnership acquired an additional 20% interest in Centrahoma which brings the Partnership’s total ownership interest to 40%.  Our interest in Centrahoma is accounted for under the equity method.

We believe the equity method is an appropriate means for us to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. We use the following types of evidence of a loss in value to identify a loss in value of an investment that is other than a temporary decline. Examples of a loss in value may be identified by:

·Our belief in the ability to recover the carrying amount of the investment;

·A current fair value of an investment that is less than its carrying amount; and

·Other operational criteria that cause us to believe the investment may be worth less than otherwise accounted for by using the equity method.

Derivative Instruments

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities.  The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception.

To the extent derivative instruments designated as cash flow hedges are effective, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings.  Effectiveness is evaluated by the derivative instrument’s ability to offset changes in fair value or cash flows of the underlying hedged item.  Any change in the fair value resulting from ineffectiveness is recognized immediately in earnings.  Changes in the fair value of derivative instruments designated as fair value hedges, as well as the changes in the fair value of the underlying hedged item, are recognized currently in earnings.  Any differences between the changes in the fair values of the hedged item and the derivative instrument represent gains or losses from ineffectiveness.  For the six months ended June 30, 2008 and 2007, the Partnership did not designate any cash flow or fair value hedges.

In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the sale of natural gas, propane, and other NGLs, that under SFAS 133, qualify for designation as a normal purchase or sales contract. Such contracts are normally exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual

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accounting.  As of June 30, 2008, the Partnership had not designated any forward physical contracts as normal purchase or sales contracts.

All derivative instruments other than those designated as cash flow hedges, fair value hedges or normal purchase or sale are marked to market through revenue or purchased product costs, the same account as the item hedged.  Changes in risk management activities are reported in cash flow from operating activities on the accompanying Condensed Consolidated Statement of Cash Flows.

The change in market value of contracts, realized and unrealized, are recorded as a component of revenue, purchase product costs or facility expenses.  Revenue gains and losses relate to contracts utilized to hedge the cash flow for the sale of a product.  Purchased product costs relate to contracts utilized to hedge costs, typically in a keep whole arrangement.  Facility expenses related to a contract utilized to hedge electricity costs.

Recent Accounting Pronouncements

Refer to Note 2 of the accompanying Condensed Consolidated Financial Statements for information regarding recent accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk includes the risk of loss arising from adverse changes in market rates and prices.  We face market risk from commodity price changes and, to a lesser extent, interest rate changes.

Commodity Price Risk

Our primary risk management objective is to reduce downside volatility in our cash flows arising from changes in commodity prices related to future sales or purchases of natural gas, NGLs and crude oil.  Swaps and futures contracts may allow us to reduce downside volatility in our realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in our sales of physical product.  While we largely expect our realized derivative gains and losses to be offset by increases or decreases in the value of our physical sales, we will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative positions that will have no offset.  The volatility in any given period related to unrealized gains or losses can be significant to our overall results, however, we ultimately expect those gains and losses to be offset when they become realized.  A committee, comprised of the senior management team of our general partner, oversees all of our risk management activity and continually monitors the risk management program and expects to continue to adjust our financial positions as conditions warrant.

To mitigate our cash flow exposure to fluctuations in the price of NGLs, we have primarily entered into derivative financial instruments relating to the future price of crude oil. To mitigate our cash flow exposure to fluctuations in the price of natural gas, we primarily utilize derivative financial instruments relating to the future price of natural gas.  As a result of these transactions, we have mitigated a significant portion of our expected commodity price risk with agreements expiring at various times through the fourth quarter of 2011.  The margins earned from condensate sales are directly correlated with crude oil prices.

We utilize a combination of futures contracts, fixed-price forward contracts, fixed-for-floating price swaps and options on the over-the-counter (“OTC”) market. These types of contracts allow us to manage volatility in our margins because corresponding losses or gains on the financial instruments are generally offset by gains or losses in our physical positions.

We may enter into physical and/or financial positions to manage the risks related to commodity price exposure for our marketing activities.  Due to the timing of purchases and sales, direct exposure to price volatility may result because there is no longer an offsetting purchase or sale that remains exposed to market pricing.  Through marketing and derivative activities, direct price exposure may occur naturally or we may choose direct exposure when it is favorable as compared to the keep-whole risk.

We conduct a standard credit review on counterparties and have agreements containing collateral requirements where deemed necessary.  We use standardized swap agreements that allow for offset of positive and negative exposures.  We may be subject to margin deposit requirements under OTC agreements (with non-bank counterparties) that we plan to meet with letters of credit.  Such funding requirements could exceed our letter of credit availability on our credit line.  If we were unable to meet these margin calls with letters of credit, we would be forced to sell product to meet the margin calls, or to terminate the corresponding futures contracts.  If we are forced to sell product to meet margin calls, we may have to sell product at prices that are not advantageous.

The use of derivative instruments may expose us 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) sales volumes are less than expected, potentially requiring

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market purchases to meet commitments, or (iii) our 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 we enter into derivative instruments, we may be prevented from realizing the benefits of favorable price changes in the physical market.  We are similarly insulated, however, against unfavorable changes in such prices.

The following tables provide information on our specific derivative positions related to long liquids positions at June 30, 2008, including the weighted average prices (“WAVG”):

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2008	3,259	$	67.05	$	78.18	$	(37,556	)
2009	3,425	67.50		77.83		(78,029		)
2010 (Apr - Dec)	2,010	66.52		74.71		(32,958		)
2011	1,706	80.00		104.50		(21,693		)

WTI Crude Puts	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		Fair Value (in thousands)
2008	3,605	$	80.00	$	98
2009	2,413	80.00		1,269
2010	1,191	80.00		1,370
2011	1,818	80.00		2,666

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2008	150	$	69.76	$	(1,950	)
2010 (Jan - Sep)	1,568	65.61		(29,438		)

The following tables provide information on the specific derivative positions related to keep-whole positions of our taxable subsidiary at June 30, 2008, including the weighted average prices (“WAVG”):

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2008	2,210	$	65.17	$	(30,604	)
2009	3,534	68.36		(90,209		)
2010	2,428	70.25		(56,273		)
2011	3,027	87.66		(48,195		)
2012 (Jan)	2,142	91.50		(2,562		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2008	22,029	$	8.42	$	21,540
2009	18,934	8.11		27,519
2010	10,806	8.41		10,340
2011	14,662	8.88		10,573

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2008	34,260	$	1.07	$	(5,310	)

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2008	10,488	$	1.27	$	(1,956	)

Iso Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2008	3,272	$	1.29	$	(612	)

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2008	7,914	$	1.58	$	(2,125	)

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We have a contract with one of the largest producers in the Appalachia region which creates a floor on the frac spread that can be realized on a specified volume purchased.  Under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), the value of this contract is marked based on an index price through purchased product costs.  As of June 30, 2008, the estimated fair value of this contract was $(12.9) million.

We have a contract which gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations. Under SFAS 133, the value of the derivative component of this contract is marked to market through facilities expense.  As of June 30, 2008, the estimated fair value of this contract was $0.4 million.

The following table provides information on the derivative positions that we have entered into subsequent to June 30, 2008:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)
2009	818	$	123.73
2010	774	121.45
2011	1,201	120.93

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)
2009	5,466	$	8.63
2010	5,149	8.76
2011	7,927	8.63

Management periodically estimates the effects of its hedge program and further changes in crude oil prices on the cash flow from operations, for the six months ending December 31, 2008, as computed on an annualized basis.  Management’s analysis considers a hypothetical change in oil prices, derivative instruments outstanding as of July 1, 2008, no change in natural gas prices, and production estimated through December 31, 2008.

·As crude oil prices move from $145 per barrel to $105 per barrel, our operating cash flow decreases approximately $2.2 million for every $1 per barrel decrease in crude oil prices;

·As crude oil prices move from $105 per barrel to $85 per barrel, our operating cash flow decreases approximately $2.5 million for every $1 per barrel decrease in crude oil prices; and

·As crude oil prices move from $85 per barrel to $65 per barrel, our operating cash flow decreases approximately $1.7 million for every $1 per barrel decrease in crude oil prices.

Management’s analysis also considers a hypothetical change in natural gas prices, derivative instruments outstanding as of July 1, 2008, no change in crude oil prices, and production estimated through December 31, 2008, as computed on an annualized basis.

·As natural gas prices increase by $0.10 per MMBtu in any price range, our operating cash flow decreases approximately $0.8 million.

We consider the stated hypothetical change in commodity prices to be reasonable given current and historic market performance.  The sensitivity analysis presented does not consider the actions management may take to mitigate our exposure to changes, nor does it consider the effects that such hypothetical adverse changes may have on overall economic activity.  Actual changes in market prices may differ from hypothetical changes.  The effect of the stated theoretical changes represents potential cash outflows in our Condensed Consolidated Statements of Cash Flows.

Interest Rate

Our primary interest rate risk exposure results from the revolving portion of the Partnership Credit Agreement that has a borrowing capacity of $350.0 million entered into on February 20, 2008. As of May 9, 2008, the Partnership had no outstanding borrowings on the Partnership Credit Agreement. The debt related to this agreement bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing. We may make use of interest rate swap agreements in the future, to adjust the ratio of fixed and floating rates in our debt portfolio.

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Long-Term Debt	Interest Rate	Lending Limit		Due Date	Outstanding at June 30, 2008
Partnership Credit Agreement	Variable	$	350.0 million	February 2013	—
2014 Senior Notes	Fixed	$	225.0 million	November 2014	$	225.0 million
2016 Senior Notes	Fixed	$	275.0 million	July 2016	$	275.0 million
2018 Senior Notes	Fixed	$	500.0 million	April 2018	$	500.0 million

Based on our overall interest rate exposure at June 30, 2008, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our credit facility would result in no change earnings over a 12-month period.  As of August 4, 2008, the Partnership had no outstanding borrowings on the Partnership Credit Agreement, therefore a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under the Partnership Credit Agreement would result in no change earnings over a 12-month period.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of June 30, 2008, an evaluation was performed under the supervision and with the participation of the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 (the “Exchange Act”)). Based on that evaluation, the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, concluded the Partnership’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is (a) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (b) accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.

Changes in Internal Controls Over Financial Reporting

ERP System Implementation

In May 2007, the Partnership began the phased implementation of an Enterprise Resource Planning (“ERP”) system. Implementing an ERP system involves significant changes in business processes that management believes will provide meaningful benefits, including more standardized and efficient processes throughout the Partnership. As a result of this implementation, some internal controls over financial reporting have been changed to address the new environment associated with the implementation of this system. While the Partnership believes that this new system will strengthen its internal controls over financial reporting, there are inherent risks in implementing any new system and the Partnership will continue to evaluate and test these control changes in order to provide certification as of year-end on the effectiveness, in all material respects, of the Partnership’s internal controls over financial reporting.

Except as described above, there were no other changes in the Partnership’s internal controls over financial reporting during the quarter ended June 30, 2008, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are subject to a variety of risks and disputes, and are a party to various legal proceedings in the normal course of our business. We maintain insurance policies in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business interruption to the Partnership (“MarkWest”); 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 provision and accruals for potential losses associated with all legal actions have been made in the 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. The NOPV is associated

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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 Production Company and leased and operated by a subsidiary, MarkWest Energy Appalachia, LLC. The NOPV sets forth six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1,070,000. 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 a motion to dismiss one of the counts of violations, which involves $825,000 of the $1,070,000 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 defenses to the remaining counts and will vigorously defend all applicable assertions of violations at the hearing.

Related to the above referenced 2004 pipeline explosion and fire incident, MarkWest Hydrocarbon and the Partnership have filed an action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed to the U.S. District Court for the District of Colorado, (Civil Action No. 1:05-CV-1948, on October 7, 2005) against their All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain costs related to the pipeline incident. The costs include internal costs incurred for damage to, and loss of use of the pipeline, equipment and products; extra transportation costs incurred for transporting the liquids while the pipeline was out of service; reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). Following initial discovery, MarkWest was granted leave of the Court to amend its complaint to add a bad faith claim and a claim for punitive damages. The Partnership has not provided for a receivable for any of the claims in this action because of the uncertainty as to whether and how much it would ultimately recover under the policies.  The Defendant insurance companies and MarkWest had each filed separate summary judgment motions in the action.  On April 23, 2008, the Court issued an order granting Defendant insurance companies’ motion for summary judgment.  The Partnership believes the Court’s analysis and decision is in error, legally and factually, on numerous grounds and has filed an appeal of this Order to the 10^th Circuit Court of Appeals.

With regard to the Partnership’s Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28^th Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128^th 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, 214^th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), set forth claims for wrongful death, personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area or from products Defendants allegedly manufactured, processed, used, or distributed. The actions have been and are being vigorously defended, and based on initial evaluation and consultations, it appears at this time that these actions should not 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 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.

Item 1A. Risk Factors

There has been no material change in the risk factors set forth in Part I, Item 1A, “Risk Factors” in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2007.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

Please see our Current Reports on Form 8-K filed with the Securities and Exchange Commission on April 15, 2008 and May 1, 2008.

Item 3.     Defaults Upon Senior Securities

None.

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Item 4.Submission of Matters to a Vote of Security Holders

At the close of business on April 14, 2008, the record date for the determination of unitholders entitled to vote at the Partnership’s annual meeting, there were 56,626,295 common units of the Partnership issued and outstanding, and 48,256,797 of those common units were entitled to vote at the meeting. At the annual meeting of stockholders held on June 4, 2008, there were not less than 40,461,566 common units, or approximately 83.8% of the outstanding common units, represented at the meeting and by proxy, therefore establishing the presence of a quorum. The Partnership’s unitholders were presented with and asked to vote on two proposals. The following are the results of the voting:

Proposal No. 1:

The election of John M. Fox, Keith E. Bailey, Michael L. Beatty, Charles K. Dempster, Donald C. Heppermann, William A. Kellstrom, Anne E. Fox Mounsey, William P. Nicoletti, Frank M. Semple and Donald D. Wolf as Directors of MarkWest Energy GP, L.L.C., the general partner of the Partnership, to hold office for a one-year term expiring at the 2009 Annual Meeting of Common Unitholders:

	Number of votes
Director Nominees	For	Authority Withheld
John M. Fox	40,050,652	410,914
Keith E. Bailey	40,081,523	380,042
Michael L. Beatty	40,080,638	380,928
Charles K. Dempster	40,087,223	374,342
Donald C. Heppermann	37,217,508	3,244,057
William A. Kellstrom	40,083,773	377,792
Anne E. Fox Mounsey	40,043,508	418,058
William P. Nicoletti	40,080,207	381,358
Frank M. Semple	40,060,064	401,501
Donald D. Wolf	40,077,501	384,064

There were no abstentions or broker non-votes applicable to the election of directors.

Proposal No. 2:

The ratification of Deloitte & Touche LLP as the Company’s independent accountants for the fiscal year ending December 31, 2008:

For	40,243,316
Against	100,498
Abstained	117,750

Abstentions had the effect of votes “against” this proposal. Broker non-votes were not counted as votes “for” or “against” this proposal and therefore had no impact on the outcome.

In accordance with the above, each of the nominees for election to the Board of Directors received the requisite number of votes required for election and proposal number two received the requisite number of votes for approval. Accordingly, Mr. Fox, Mr. Bailey, Mr. Beatty, Mr. Dempster, Mr. Heppermann, Mr. Kellstrom, Ms. Fox Mounsey, Mr. Nicoletti, Mr. Semple and Mr. Wolf have been elected as Directors to serve for a term expiring at the 2009 Annual Meeting of Common Unitholders. In addition, the selection of Deloitte & Touche LLP as the Partnership’s independent registered public accountants for the fiscal year ending December 31, 2008, was ratified.

Item 5. Other Information

None.

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Item 6. Exhibits

4.1(1)	Indenture dated as of April 15, 2008 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, and the several guarantors named therein, and Wells Fargo Bank, N.A., as trustee.
4.2(1)	Form of 8¾% Series A and Series B Senior Notes due 2018 with attached notation of Guarantees (incorporated by reference to Exhibits A and D of Exhibit 4.1 hereto).
4.3(1)	Registration Rights Agreement dated as of April 15, 2008 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, and the several guarantors named therein, and J.P. Morgan Securities Inc., RBC Capital Markets Corporation, Wachovia Capital Markets, LLC, Banc of America Securities LLC, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Fortis Securities LLC and SunTrust Robinson Humphrey, Inc.
4.4(2)	Registration Rights Agreement dated as of May 1, 2008 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, and the several guarantors named therein, and J.P. Morgan Securities Inc., RBC Capital Markets Corporation, Wachovia Capital Markets, LLC, Banc of America Securities LLC, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Fortis Securities LLC and SunTrust Robinson Humphrey, Inc.
10.1*	Form of Second Amended and Restated Indemnification Agreement dated April 24, 2008 by and among MarkWest Energy Partners, L.P., MarkWest Energy GP, L.L.C., and each director and officer of MarkWest Energy GP, L.L.C., including the following named executive officers:  Frank Semple, President and Chief Executive Officer; Nancy Buese, Senior Vice President and Chief Financial Officer; Randy Nickerson, Senior Vice President and Chief Commercial Officer; John Mollenkopf, Senior Vice President and Chief Operations Officer; and C. Corwin Bromley, Senior Vice President, General Counsel and Secretary.
10.2*	1996 Stock Incentive Plan for MarkWest Hydrocarbon, Inc.
10.3*	2006 Stock Incentive Plan for MarkWest Hydrocarbon, Inc.
31.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith
(1)	Incorporated by reference to Current Report on Form 8-K, filed with the Commission on April 15, 2008.
(2)	Incorporated by reference to Current Report on Form 8-K, filed with the Commission on May 1, 2008.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	MarkWest Energy Partners, L.P.
	(Registrant)
	By:	MarkWest Energy GP, L.L.C.,
		Its General Partner
	/s/ Frank M. Semple
Date: August 11, 2008	Frank M. Semple
	President and Chief Executive Officer
	(Principal Executive Officer)
	/s/ Nancy K. Buese
Date: August 11, 2008	Nancy K. Buese
	Senior Vice President & Chief Financial Officer
	(Principal Financial Officer and
	Principal Accounting Officer)

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