Markwest Energy Partners L P 10-Q 2008 Q3 Quarterly report

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

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2008
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                to

Commission File Number 001-31239

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

Delaware (State or other jurisdiction of incorporation or organization)	27-0005456 (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. Yesý Noo

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

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

         The number of the registrant's common units outstanding as of October 31, 2008, was 56,639,952.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at September 30, 2008 and December 31, 2007	2
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2007	3
	Unaudited Condensed Consolidated Statement of Changes in Partners' Capital and Comprehensive Income for the nine months ended September 30, 2008	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007	5
	Unaudited Notes to the Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	66
Item 4.	Controls and Procedures	69
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	70
Item 1A.	Risk Factors	72
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	72
Item 3.	Defaults Upon Senior Securities	72
Item 4.	Submission of Matters to a Vote of Security Holders	72
Item 5.	Other Information	72
Item 6.	Exhibits	73
SIGNATURES		74

        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

1

PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

			September 30, 2008			December 31, 2007
ASSETS
Current assets:
	Cash and cash equivalents		$	104,913		$	37,695
	Trading securities			—			3,674
	Available for sale securities			—			6,474
	Receivables, net of allowances of $178 and $194, respectively			149,193			130,877
	Inventories			60,815			30,328
	Fair value of derivative instruments			17,065			9,441
	Deferred income taxes			17,055			16,667
	Other current assets			14,417			51,178
		Total current assets		363,458			286,334
Property, plant and equipment				1,412,964			976,169
Less: accumulated depreciation				(62,743	)		(145,360	)
		Total property, plant and equipment, net		1,350,221			830,809
Other long-term assets:
	Investment in unconsolidated affiliates			82,235			58,709
	Intangibles, net of accumulated amortization of $32,539 and $45,753, respectively			705,839			326,722
	Goodwill			38,055			—
	Deferred financing costs, net of accumulated amortization of $2,588 and $8,206, respectively			17,352			13,428
	Deferred contract cost, net of accumulated amortization of $1,248 and $1,014, respectively			2,002			2,236
	Fair value of derivative instruments			30,482			5,414
	Other long-term assets			1,522			1,043
		Total other long-term assets		877,487			407,552
		Total assets	$	2,591,166		$	1,524,695
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Accounts payable		$	164,883		$	107,107
	Accrued liabilities			150,303			79,869
	Fair value of derivative instruments			91,135			77,426
		Total current liabilities		406,321			264,402
Deferred income taxes				6,563			8,500
Fair value of derivative instruments				125,437			84,051
Long-term debt, net of discounts of $12,209 and $2,805, respectively				987,791			552,695
Other long-term liabilities				4,124			51,073
Non-controlling interest in consolidated subsidiaries				3,169			524,583
Commitments and contingencies (Note 20)
Partners' Capital:
Common units, 56,640 and 22,861 units outstanding, respectively				1,057,761			38,463
Accumulated other comprehensive income, net of tax				—			928
		Total partners' capital		1,057,761			39,391
		Total liabilities and partners' capital	$	2,591,166		$	1,524,695

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

2

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

			Three months ended September 30,						Nine months ended September 30,
			2008			2007			2008			2007
Revenue:
	Revenue		$	303,560		$	199,934		$	866,760		$	590,342
	Derivative gain (loss)			262,811			(24,386	)		(96,030	)		(52,208	)
		Total revenue		566,371			175,548			770,730			538,134
Operating expenses:
	Purchased product costs			171,539			107,609			479,747			354,733
	Derivative loss (gain) related to purchased product costs			67,574			14,450			(11,520	)		19,158
	Facility expenses			28,213			18,869			75,641			48,750
	Derivative loss (gain) related to facility expenses			1,748			(245	)		1,395			351
	Selling, general and administrative expenses			15,331			11,164			54,406			50,545
	Depreciation			17,510			11,133			48,533			28,632
	Amortization of intangible assets			10,732			4,168			28,050			12,504
	Loss on disposal of property, plant and equipment			6			229			9			383
	Accretion of asset retirement obligations			32			30			97			85
	Impairment of long-lived assets			—			356			5,009			356
		Total operating expenses		312,685			167,763			681,367			515,497
		Income from operations		253,686			7,785			89,363			22,637
Other income (expense):
	(Loss) earnings from unconsolidated affiliates			(196	)		1,264			1,932			4,687
	Interest income			1,421			403			3,597			3,923
	Interest expense			(18,928	)		(10,202	)		(47,527	)		(28,670	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(1,080	)		(771	)		(7,287	)		(2,222	)
	Miscellaneous (expense) income			(99	)		1,319			1,043			252
		Income (loss) before non-controlling interest in net income of consolidated subsidiaries and provision for income tax		234,804			(202	)		41,121			607
Non-controlling interest in net (income) loss of consolidated subsidiaries				(122	)		(15,131	)		3,271			(24,653	)
		Income (loss) before provision for income tax		234,682			(15,333	)		44,392			(24,046	)
Provision for income tax (expense) benefit:
	Current			(7,544	)		(12,254	)		(22,876	)		(22,903	)
	Deferred			(40,592	)		20,133			6,414			33,180
		Total provision for income tax		(48,136	)		7,879			(16,462	)		10,277
		Net income (loss)	$	186,546		$	(7,454	)	$	27,930		$	(13,769	)
Net income (loss) per common unit(1) (Note 18):
	Basic		$	3.29		$	(0.33	)	$	0.57		$	(0.60	)
	Diluted		$	3.26		$	(0.33	)	$	0.56		$	(0.60	)
Weighted average number of outstanding common units(1):
		Basic		56,635			22,863			49,123			22,852
		Diluted		57,224			22,863			49,602			22,852
Cash distribution declared per common unit(1)			$	0.63		$	0.19		$	1.42		$	0.51

(1)

All unit and per unit data where applicable has been adjusted to reflect the 1.9051 Exchange Ratio to give effect to the Merger on February 21, 2008 (see Note 3). The Partnership declared a distribution of $0.64 per common unit on October 22, 2008, for the period ended September 30, 2008, $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 19).

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

3

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
Common units issued for vested phantom units			14			63			—			63
Dividends paid			—			(4,338	)		—			(4,338	)
Distributions paid			—			(70,577	)		—			(70,577	)
Share-based compensation related to equity awards			—			8,251			—			8,251
APIC pool for excess tax benefits under SFAS 123R			—			717			—			717
Redemption and Merger:
	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 income			—			27,930			—			27,930
Realized gain on marketable securities, net of taxes of $558			—			—			(928	)		(928	)
Comprehensive income			—			—			—			27,002
September 30, 2008			56,640		$	1,057,761		$	—		$	1,057,761

(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 Merger on February 21, 2008 (see Note 3).

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

4

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)

				Nine months ended September 30,
				2008			2007
Cash flows from operating activities:
Net income (loss)				$	27,930		$	(13,769	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities (net of acquisitions):
	Depreciation				48,533			28,632
	Amortization of intangible assets				28,050			12,504
	Impairment of long-lived assets				5,009			356
	Amortization of deferred financing costs and discount				7,287			2,222
	Accretion of asset retirement obligations				97			85
	Amortization of gas contract				234			234
	Phantom unit compensation expense				9,261			1,240
	Participation Plan compensation expense				4,545			13,263
	Restricted stock compensation expense				75			590
	Non-controlling interest in net (loss) income of consolidated subsidiaries				(3,271	)		24,653
	Equity in earnings of unconsolidated affiliates				(1,932	)		(4,687	)
	Distributions from unconsolidated affiliates				5,445			9,345
	Unrealized loss on derivative instruments				22,403			67,701
	Loss on disposal of property, plant and equipment				9			383
	Deferred income taxes				(6,414	)		(33,140	)
	Unrealized gain on trading securities				—			(4	)
	Gain on sale of available for sale securities				(1,238	)		(562	)
	Loss (gain) on sale of trading securities				104			(14	)
	Net sales (purchases) of trading securities				2,400			(3,683	)
	Other				(43	)		(114	)
	Changes in operating assets and liabilities, net of working capital acquired:
		Receivables			(18,316	)		(17,634	)
		Inventories			(30,487	)		(6,195	)
		Other current assets			36,761			(11,940	)
		Accounts payable and accrued liabilities			78,884			26,878
		Other long-term assets			719			—
		Other long-term liabilities			87			191
			Net cash provided by operating activities		216,132			96,535
Cash flows from investing activities:
	Acquisitions				(41,300	)		(46	)
	Equity investments				(27,038	)		—
	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			1,210
	Capital expenditures				(316,881	)		(229,099	)
	Proceeds from disposal of property, plant and equipment				78			36
			Net cash flows used in investing activities		(648,794	)		(227,899	)
Cash flows from financing activities:
	Proceeds from long-term debt				958,234			339,000
	Payments of long-term debt				(515,001	)		(276,500	)
	Payments for debt issuance costs, deferred financing costs and registration costs				(21,213	)		(521	)
	Proceeds from private placements, net				—			134,950
	Proceeds from public offering, net				171,395			—
	Exercise of stock options				375			116
	Cash paid for taxes related to net settlement of share-based payment awards				(61	)		—
	APIC pool for excess tax benefits under SFAS 123R				717			222
	Payment of dividends and distributions				(74,915	)		(11,756	)
	Distributions to MarkWest Energy unitholders prior to the Merger				(19,651	)		(46,557	)
			Net cash flows provided by financing activities		499,880			138,954
Net increase in cash					67,218			7,590
Cash and cash equivalents at beginning of year					37,695			48,844
Cash and cash equivalents at end of period				$	104,913		$	56,434
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized				$	29,558		$	19,509
Cash paid for income taxes					17,814			19,896
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment				$	67,826		$	18,796
Interest capitalized on construction in progress					5,035			2,750
Property, plant and equipment asset retirement obligation					9			144
Merger step-up of fair value					605,100			—
Issuance of common units for vesting of share-based payment awards					2,492			1,429

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

5

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" or the "Partnership," 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. On July 31, 2008, the Partnership acquired a controlling operating interest in Wirth Gathering, a general partnership, as part of the acquisition of PQ Gathering Assets, LLC. The 50% interest not acquired by the Partnership is recorded asNon-controlling interest in consolidated subsidiaries in the accompanying Condensed Consolidated Balance Sheets. 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

6

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

1. Organization and Basis of Presentation (Continued)

nine months ended September 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 and the acquisition of PQ Gathering Assets LLC, the Partnership has recorded a total of $38.1 million of goodwill on the accompanying Condensed Consolidated Balance Sheets as of September 30, 2008 (see Note 3 and Note 4). 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 5). 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:

•

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.

7

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

2. Recent Accounting Pronouncements (Continued)

        In October 2008, the FASB issued Staff Position No. FAS 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active ("FSP 157-3"). FSP 157-3 clarifies the application of SFAS 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets. FSP 157-3 is effective immediately and includes those periods for which financial statements have not been issued. The Partnership is not impacted by the issuance of FSP 157-3.

        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 No. 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 adoption of SFAS 141R will not have a material impact on the Partnership's condensed consolidated financial statements.

        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 adoption of SFAS 160 will not have a material impact on the Partnership's condensed consolidated financial statements.

8

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

2. Recent Accounting Pronouncements (Continued)

        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.

        In April 2008, the FASB issued Staff Position No. FAS 142-3,Determination of the Useful Life of Intangible Assets ("FSP 142-3"). 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 SFAS 142. 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 consider 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,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities ("FSP EITF 03-6-1"). 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 adoption of FSP EITF 03-6-1 will not have any impact on the net income reported in the Partnership's Condensed Consolidated Statements of Operations, however, the reported earnings per unit may be lower than the amount reported prior to adoption.

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. 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

9

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Redemption and Merger (Continued)

1.9051 when combined with the other 1.285 units included in the stated consideration. Subject to proration, 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 16).

        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 Shares			Exchange Ratio		Common 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 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 Sheets.

10

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Redemption and Merger (Continued)

        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 the 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.

11

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Redemption and Merger (Continued)

        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.

4. Business Combination

        On July 31, 2008, the Partnership acquired a 100% interest in PQ Gathering Assets, LLC ("PQ Assets") from PetroQuest Energy, LLC. PQ Assets consisted of gathering systems located in the Woodford Shale area of southeastern Oklahoma. The acquisition also included a 50% managing partner operating interest in Wirth Gathering, a general partnership, which also owns a gathering system located in the Woodford Shale area. PQ Assets was renamed MarkWest McAlester, L.L.C. ("MarkWest McAlester"). The Partnership's consolidated financial statements include the results of operations for MarkWest McAlester from July 31, 2008. The Partnership is in the process of obtaining third-party valuations of the net assets and liabilities acquired, thus the purchase price allocation is

12

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Business Combination (Continued)

subject to further adjustment, which could impact depreciation and amortization expense. The following table summarizes the preliminary cost and allocation of the acquisition (in thousands):

Acquisition costs:
Cash consideration	$	41,300
Total	$	41,300
Allocation of acquisition costs:
Property, plant and equipment	$	27,270
Customer contracts and relationships		16,360
Goodwill(1)		594
Non-controlling interest		(2,924	)
Total	$	41,300

(1)

Goodwill was recorded in the Southwest segment.

5. 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 September 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.

13

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value (Continued)

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.

Trading Securities

        Trading securities consist exclusively of auction rate securities as of September 30, 2008 and are included inOther 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 September 30, 2008.

14

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value (Continued)

        The following table presents the financial instruments carried at fair value as of September 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	$	—	$	45,011		$	2,536		$	47,547
	Other long-term assets		—		—			1,198			1,198
Total assets at fair value		$	—	$	45,011		$	3,734		$	48,745
Liabilities:
	Fair value of derivative instruments	$	—	$	(203,171	)	$	(13,401	)	$	(216,572	)
Total liabilities at fair value		$	—	$	(203,171	)	$	(13,401	)	$	(216,572	)

Changes in Level 3 fair value measurements

        The tables below include a rollforward of the balance sheet amounts for the three and nine months ended September 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 June 30, 2008			Total gains or losses (realized or unrealized) included in earnings			Purchases, issuances and settlements		Transfers in or out of Level 3		Fair value September 30, 2008
Assets:
	Derivatives	$	1,242		$	1,294	(a)	$	—	$	—	$	2,536
	Trading securities		1,198			—			—		—		1,198
Liabilities:
	Derivatives		(23,762	)		6,835	(a)		3,526		—		(13,401	)

15

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value (Continued)

		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 September 30, 2008
Assets:
	Derivatives	$	111		$	2,425	(a)	$	—		$	—	$	2,536
	Trading securities		3,674			(76	)(b)		(2,400	)		—		1,198
Liabilities:
	Derivatives		(36,828	)		4,999	(a)		18,428			—		(13,401	)

(a)

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

(b)

Gains and losses are recorded in miscellaneous (expense) income.

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 September 30, 2008, there were not any assets or liabilities to be measured at fair value on a nonrecurring basis.

6. Marketable Securities

        As of December 31, 2007, the Partnership held short-term equity investments classified asTrading securities in the accompanying Condensed Consolidated Balance Sheets. During the first nine 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 September 30, 2008, the $1.2 million balance associated with these securities has been reclassified toOther 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 (Losses)		Fair Value
September 30, 2008
	Trading Securities	$	1,198	$	—	$	1,198

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

16

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

6. Marketable Securities (Continued)

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

7. Receivables and Other Current Assets

        Receivables consist of the following (in thousands):

		September 30, 2008		December 31, 2007
Trade, net		$	142,123	$	121,099
Other			7,070		9,778
	Total receivables	$	149,193	$	130,877

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

		September 30, 2008		December 31, 2007
Margin deposits		$	—	$	40,260
Prepaid fuel			10,488		1,605
Income tax receivable			—		3,212
Merger finance costs			—		857
Prepaid merger costs			—		3,914
Prepaid insurance			1,974		333
Prepaid other			1,955		997
	Total other current assets	$	14,417	$	51,178

17

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

8. Property, Plant and Equipment

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

		September 30, 2008			December 31, 2007
Natural gas gathering facilities, natural gas pipelines and other		$	888,042		$	657,878
Gas processing plants			225,779			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			246,186			51,553
	Property, plant and equipment	$	1,412,964		$	976,169
Less: accumulated depreciation			(62,743	)		(145,360	)
	Total property, plant and equipment, net	$	1,350,221		$	830,809

        The Partnership capitalizes interest on major projects during construction. For the three and nine months ended September 30, 2008, the Partnership capitalized interest, including deferred finance costs, of $2.1 million and $5.0 million, respectively. For the three and nine months ended September 30, 2007, the Partnership capitalized interest, including deferred finance costs, of $0.5 million and $2.8 million, respectively.

9. Intangible Assets and Goodwill

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

Segment		September 30, 2008		December 31, 2007
Southwest		$	388,176	$	148,488
Northeast			64,412		—
Gulf Coast			253,251		178,234
	Total	$	705,839	$	326,722

        Amortization expense related to the intangible assets was $10.7 million and $4.2 million for the three months ended September 30, 2008 and 2007, respectively, and $28.1 million and $12.5 million for the nine months ended September 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 addition, the purchase price in excess of the fair value of the net assets acquired in the purchase of PQ Assets was also 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

18

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

9. Intangible Assets and Goodwill (Continued)

recoverable. As of September 30, 2008, goodwill was $38.1 million. The Partnership did not have goodwill recorded prior to 2008.

10. 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 non-operating interest 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 less than $0.1 million for both the three and nine months ended September 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. In September 2008, Hurricane Ike caused wind and water damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions, including damage to several onshore and offshore facilities of Starfish. Due to the damage in the region, the operations of Starfish have been shut down since the middle of September resulting in a decrease in the Partnership'sEarnings from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations. The Partnership's share of Starfish's net (loss) income was ($0.2) million and $1.3 million for the three months ended September 30, 2008 and 2007, respectively, and $1.9 million and $4.7 million for the nine months ended September 30, 2008 and 2007, respectively. Summarized financial information for 100% of Starfish is as follows (unaudited, in thousands):

	Three months ended September 30,					Nine months ended September 30,
	2008			2007		2008		2007
Revenues	$	5,247		$	8,078	$	19,624	$	25,148
Operating (loss) income		(399	)		2,962		3,800		10,515
Net (loss) income		(355	)		2,671		4,188		9,801

        The table below shows the carrying value of the Partnership's equity investments (in thousands):

		September 30, 2008		December 31, 2007
Investment in Starfish		$	55,143	$	58,709
Investment in Centrahoma			27,092		—
	Total investment in unconsolidated affiliates	$	82,235	$	58,709

19

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

11. Asset Retirement Obligation

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

Asset retirement obligation as of December 31, 2007		$	1,635
	Liabilities incurred		9
	Accretion expense		97
Asset retirement obligation as of September 30, 2008		$	1,741

        At September 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 ofOther long-term liabilities in the accompanying Condensed Consolidated Balance Sheets.

12. 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 of 2008 indicated an impairment of 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 nine months ended September 30, 2008.

        An analysis completed during the third quarter of 2007 determined that a system located in the Partnership's Southwest segment had future estimated cash inflows estimated to be near zero because the system was shut-in for a year, and as such the carrying amounts of the assets exceeded the estimated undiscounted cash flows. It was determined that an impairment of the system had occurred. Fair value of the long-lived assets was determined based on Management's opinion that the idle assets had no economic value. Therefore, an impairment of long-lived assets of $0.4 million was recognized during the three months ended September 30, 2007.

20

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Long-Term Debt

        Debt is summarized below (in thousands):

			September 30, 2008		December 31, 2007
Credit Facility
	Revolver facility, 7.09% interest at December 31, 2007, retired February 2008		$	—	$	55,500
	Revolver facility, 5.50% interest at September 30, 2008, due February 2013			—		—
Senior Notes
	Senior Notes, 6.875% interest, net of discount of $10,088 and $0, respectively, due November 2014			214,912		225,000
	Senior Notes, 8.5% interest, net of discount of $912 and $2,805, respectively, due July 2016			274,088		272,195
	Senior Notes, 8.75% interest, net of discount of $1,209 and $0, respectively, due April 2018			498,791		—
		Total long-term debt	$	987,791	$	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 credit 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 credit 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, 2008. The Partnership recorded a charge of $4.2 million to write off the deferred financing costs associated with the term loan, which is included inAmortization 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 September 30, 2008, the Partnership had zero borrowings outstanding under the revolving credit facility and approximately $270.4 million of available borrowings, including outstanding letters of credit of $79.6 million.

        The borrowings under the revolving credit 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

21

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Long-Term Debt (Continued)

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 September 30, 2008, the interest rate for borrowings under the Partnership Credit Agreement would have been LIBOR plus 1.50%, or 5.50%.

Senior Notes

        On April 15, 2008, the Partnership and its wholly-owned subsidiary, MarkWest Energy Finance Corporation ("MarkWest Finance"), completed a private placement, subsequently registered, 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, are 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.

        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 September 30, 2008: $225.0 million principal due in November 2014 (the "2014 Senior Notes"), and $275.0 million principal due in July 2016 (the "2016 Senior Notes" and all together with the 2014 Senior Notes and 2018 Senior Notes, the "Senior Notes"). The estimated fair value of the Senior Notes was approximately $941.3 million and $499.8 million at September 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 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 Indentures) has occurred and is continuing, many of such covenants will be suspended during the period of time in

22

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Long-Term Debt (Continued)

which the foregoing requirements are met or will terminate entirely, in which case the Partnership and its subsidiaries will cease to be subject to such terminated covenants.

14. 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 No. 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 provision for income tax expense totaled $16.5 million for the nine months ended September 30, 2008, resulting in an effective tax rate of 37.1%. 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.

23

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Income Taxes (Continued)

        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 nine months ended September 30, 2008 is as follows (in thousands):

	Three months ended September 30, 2008
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	77,503		$	159,259		$	(2,080	)	$	234,682
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate	$	27,126		$	—		$	—		$	27,126
Permanent items		(16	)		—			—			(16	)
State income taxes net of federal benefit		1,967			1,001			—			2,968
Provision on income from Class A units		18,064			—			—			18,064
Other		(6	)		—			—			(6	)
Provision for income tax	$	47,135		$	1,001		$	—		$	48,136

	Nine months ended September 30, 2008
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	1,876		$	48,020		$	(5,504	)	$	44,392
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate	$	657		$	—		$	—		$	657
Permanent items		8			—			—			8
State income taxes net of federal benefit		47			302			—			349
Provision on income from Class A units		8,188			—			—			8,188
Write-off of deferred income tax assets		7,471			—			—			7,471
Other		(211	)		—			—			(211	)
Provision for income tax	$	16,160		$	302		$	—		$	16,462

15. 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 13), and the remainder is being used to partially fund the Partnership's 2008 capital expenditure requirements.

16. Incentive Compensation Plans

        As of September 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

24

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Incentive Compensation Plans (Continued)

("Compensation Committee"). Compensation expense is recognized under SFAS No. 123R,Share-Based Payment ("SFAS 123R").

Share-based compensation plan	Plan qualification under SFAS 123R	Further awards authorized for 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

Compensation Expense

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

	Three months ended September 30,					Nine months ended September 30,
	2008		2007			2008		2007
Phantom units	$	3,087	$	61		$	9,261	$	1,240
Distribution equivalent rights		230		64			468		189
Restricted stock		—		217			75		590
General partner interests under Participation Plan		—		(510	)		5,470		13,263
Total compensation expense	$	3,317	$	(168	)	$	15,274	$	15,282

        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 eitherSelling, general and administrative expenses orFacility expenses in the accompanying Condensed Consolidated Statements of Operations.

        As of September 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 $20.7 million, with a weighted average remaining vesting period of approximately 1.3 years. Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP was approximately $1.8 million, with a weighted-average remaining vesting period of approximately 1.1 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.

25

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Incentive Compensation Plans (Continued)

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.

        In relation to the Merger, 772,500 phantom units have been granted to senior executives and other key employees under the 2008 LTIP during 2008. 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 September 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 $1.2 million and $2.9 million for the three and nine months ended September 30, 2008, respectively. Compensation expense related to the entire grant of 772,500 phantom units related to the Merger was approximately $2.7 million and $6.4 million for the three and nine months ended September 30, 2008, respectively.

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.

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

26

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Incentive Compensation Plans (Continued)

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 nine months ended September 30, 2008 and 2007, the Partnership was required to pay approximately $0.1 million and $0, respectively, 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)		919,185			31.93
	Vested		(17,274	)		31.79
	Forfeited		(1,000	)		34.93
Unvested at September 30, 2008			900,911			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 September 30,				Nine months ended September 30,
	2008		2007		2008		2007
Total grant-date fair value of phantom units granted during the period	$	198,080	$	—	$	29,351,463	$	821,840
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	424,015	$	—	$	549,140	$	147,605

2002 LTIP

        As of September 30, 2008, there were 146,364 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

27

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Incentive Compensation Plans (Continued)

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 nine months ended September 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 and none of the phantom units that vested were redeemed by the Partnership for cash. The amounts paid by the Partnership for income tax withholdings related to the vesting of awards under the 2002 LTIP were near zero for the nine months ended September 30, 2008 and 2007.

        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		(57,214	)		26.11
	Forfeited		(212	)		34.00
Unvested at September 30, 2008			146,364			31.46

	Three months ended September 30,				Nine months ended September 30,
	2008		2007		2008		2007
Total grant-date fair value of phantom units granted during the period	$	—	$	177,305	$	2,670,360	$	1,663,379
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	71,619	$	19,296	$	1,943,217	$	1,281,046

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 inOther long-term liabilities in the accompanying Condensed Consolidated Balance Sheets.

28

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Incentive Compensation Plans (Continued)

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 September 30,				Nine months ended September 30,
	2008		2007		2008		2007
Options exercised, cashless		—		—		1		1
Shares issued, cashless		—		—		1		1
Options exercised, cash		—		—		50		13
Shares issued, cash		—		—		50		13

        For the nine months ended September 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 nine months ended September 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 operating activity. The company recognized $0.7 million and $0.2 million for the nine months ended September 30, 2008 and 2007, respectively, related to excess tax benefits realized from the exercise of stock options.

29

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

17. 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 generally expects those gains and losses to be offset when they become realized. The Partnership does not have any trading derivative financial instruments.

        To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has 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.

30

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

17. Derivative Financial Instruments (Continued)

        The Partnership values its derivative instruments and estimates fair value as discussed in Note 5. The impact of the Partnership's commodity derivative instruments on financial position are summarized below (in thousands):

			September 30, 2008			December 31, 2007
Fair value of derivative instruments:
	Current asset		$	17,065		$	9,441
	Noncurrent asset			30,482			5,414
	Current liability			(91,135	)		(77,426	)
	Noncurrent liability			(125,437	)		(84,051	)
		Net derivative payable	$	(169,025	)	$	(146,622	)

        At September 30, 2008, the fair value of the Partnership's derivative instruments is inclusive of premium payments of $14.4 million, net of amortization. The Partnership amortizes the premium payments over the effective term of the underlying derivative option contracts through realized loss.

        The change in market value of contracts, realized and unrealized, is 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 gains and losses relate to contracts utilized to hedge costs, typically in a keep-whole arrangement. Facility expenses gains and losses relate to a contract utilized to hedge electricity costs for a facility.

        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 September 30,						Nine months ended September 30,
			2008			2007			2008			2007
Derivatives:
	Realized (loss) gain—revenue		$	(22,197	)	$	(4,013	)	$	(64,961	)	$	674
	Unrealized gain (loss)—revenue			285,008			(20,373	)		(31,069	)		(52,882	)
	Realized gain (loss)—purchased product costs			7,419			(3,490	)		15,858			(4,691	)
	Unrealized loss—purchased product costs			(74,993	)		(10,960	)		(4,338	)		(14,467	)
	Unrealized (loss) gain—facility expenses			(1,748	)		245			(1,395	)		(351	)
		Total derivative gain (loss)	$	193,489		$	(38,591	)	$	(85,905	)	$	(71,717	)

        For the three and nine months ended September 30, 2008, theRealized (loss) gain—revenue includes amortization of premium payments of $0.7 million and $1.1 million, respectively. For the three and nine months ended September 30, 2007, theRealized (loss) gain—revenue includes amortization of premium payments of $0.3 million and $0.6 million, respectively.

31

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

18. Income Per Unit

        Basic and diluted income per common unit is computed in accordance with SFAS No. 128,Earnings per Share ("SFAS 128"). 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 September 30, 2007				Nine months ended September 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		22,863		12,001		22,852		11,995
Effect of dilutive instruments		—		—		—		—
Weighted average common units and shares of common stock, respectively, outstanding during the period including the effects of dilutive instruments		22,863		12,001		22,852		11,995

        The following table shows the computation of basic and diluted net income (loss) per common unit, for the three and nine months ended September 30, 2008 and 2007, and the weighted-average units used to compute diluted net income (loss) per unit. For the three and nine months ended September 30, 2007, there is no difference between basic and diluted net loss per unit since phantom

32

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

18. Income Per Unit (Continued)

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 September 30,					Nine months ended September 30,
		2008		2007			2008			2007
Net income (loss)		$	186,546	$	(7,454	)	$	27,930		$	(13,769	)
	Weighted average common units outstanding during the period		56,635		22,863			49,123			22,852
	Effect of dilutive instruments(1)		589		—			479			—
	Weighted average common units outstanding during the period including the effects of dilutive instruments		57,224		22,863			49,602			22,852
Net income (loss) per common unit
	Basic	$	3.29	$	(0.33	)	$	0.57	��	$	(0.60	)
	Diluted	$	3.26	$	(0.33	)	$	0.56		$	(0.60	)

(1)

For the three months ended September 30, 2007, 87 units were excluded from the calculation of diluted units. For the nine months ended September 30, 2007, 111 units 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 nine months ended September 30, 2008.

19. Distribution to Unitholders and Dividends to Shareholders

        On October 22, 2008, the Partnership declared a cash distribution of $0.64 per common unit for the quarter ended September 30, 2008. The distribution will be paid on November 14, 2008, to unitholders of record as of November 4, 2008. The ex-dividend date was October 31, 2008.

        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 was 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.

33

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

20. 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 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 captionedMarkWest 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

34

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

20. Commitments and Contingencies (Continued)

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. The Partnership and the Defendant insurance companies have filed briefs in connection with the appeal.

        Also related to the above referenced 2004 pipeline explosion and fire incident, MarkWest's insurance carriers, Ace Westchester Surplus Lines Insurance Company, AEGIS Insurance Services, and Co-defendant Equitable Production Company, the pipeline owner, and its separate insurance policy with AEGIS Insurance Services, funded the 2007 settlement of the third party personal injury and property damage plaintiffs' claims inRicky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, and Civil Action No. 05-CI-00137, and in doing so exhausted the limits of MarkWest's AEGIS policy and partially utilized proceeds from MarkWest's Ace Westchester policy, an excess insurance layer. The parties and insurers all disputed the proper allocation of insurance obligations under the respective policies and the commercial agreements between MarkWest and Equitable Production Company. In the Funding Agreement for the final settlements of the underlying personal injury and property damage actions, the various insurers and defendants reserved all rights with regard to re-allocation of insurance coverage obligations by and amongst the respective insurance policies of the parties, and agreed to an ADR process to address these issues. On April 30, 2007, Ace Westchester initiated the ADR process. The principal dispute is whether the Equitable AEGIS policy should have been obligated to share/pay more in the settlements and defense costs, which would potentially result in the Ace Westchester to be refunded the amounts it paid as its policy may never have been property triggered. A mediation, held August 20, 2008, was unsuccessful, and the matter is set for binding arbitration. The Partnership will cooperate with its insurers and vigorously defend any assertions of liability, but believes this dispute should primarily be between the insurance companies as a dispute of allocation of insurance proceeds and payments among the insurance companies, and that at this time believes that this arbitration should not have a material adverse impact on the Partnership's financial position or results of operations.

        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 theGonzales case cited above); andEsmerejilda 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 captionedJesus 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.

35

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

20. Commitments and Contingencies (Continued)

        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.

21. 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 segment 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 processing and fractionation of refinery off-gas in Corpus Christi, Texas.

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

        Items belowIncome from operations in the accompanying Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any unrealized gains (losses) from derivative instruments are not allocated to individual business segments. The tables below present information about operating income for the reported segments for the three and nine months ended September 30, 2008 and 2007.

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

Three months ended September 30, 2008:			Southwest		Northeast		Gulf Coast		Total
Revenue			$	192,675	$	82,418	$	28,467	$	303,560
Operating expenses:
	Purchased product costs			120,208		51,331		—		171,539
	Facility expenses			16,670		6,172		5,085		27,927
		Operating income before items not allocated to segments	$	55,797	$	24,915	$	23,382	$	104,094
	Capital Expenditures		$	88,375	$	30,655	$	25,663	$	144,693

36

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

21. Segment Information (Continued)

Three months ended September 30, 2007:			Southwest		Northeast		Gulf Coast		Total
Revenue			$	125,242	$	49,413	$	25,279	$	199,934
Operating expenses:
	Purchased product costs			74,674		32,935		—		107,609
	Facility expenses			10,797		4,818		3,254		18,869
		Operating income before items not allocated to segments	$	39,771	$	11,660	$	22,025	$	73,456
	Capital Expenditures		$	84,667	$	1,343	$	2,378	$	88,388

        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 September 30, 2008 and 2007.

			Three months ended September 30,
			2008			2007
Total segment revenue			$	303,560		$	199,934
	Derivative gain (loss) not allocated to segments			262,811			(24,386	)
		Total revenue	$	566,371		$	175,548
Operating income before items not allocated to segments			$	104,094		$	73,456
	Derivative gain (loss) not allocated to segments			193,489			(38,591	)
	Compensation expense included in facility expenses not allocated to segments			(286	)		—
	Selling, general and administrative expenses			(15,331	)		(11,164	)
	Depreciation			(17,510	)		(11,133	)
	Amortization of intangible assets			(10,732	)		(4,168	)
	Loss on disposal of property, plant and equipment			(6	)		(229	)
	Accretion of asset retirement obligations			(32	)		(30	)
	Impairment of long-lived assets			—			(356	)
		Income from operations		253,686			7,785
	(Loss) earnings from unconsolidated affiliates			(196	)		1,264
	Interest income			1,421			403
	Interest expense			(18,928	)		(10,202	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(1,080	)		(771	)
	Miscellaneous (expense) income			(99	)		1,319
		Income (loss) before non-controlling interest in net income of consolidated subsidiaries and provision for income tax	$	234,804		$	(202	)

37

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

21. Segment Information (Continued)

Nine months ended September 30, 2008 and 2007 (in thousands):

Nine months ended September 30, 2008:			Southwest		Northeast		Gulf Coast		Total
Revenue			$	536,563	$	251,115	$	79,082	$	866,760
Operating expenses:
	Purchased product costs			322,370		157,377		—		479,747
	Facility expenses			45,189		16,161		13,341		74,691
		Operating income before items not allocated to segments	$	169,004	$	77,577	$	65,741	$	312,322
	Capital Expenditures		$	217,574	$	47,919	$	51,388	$	316,881

Nine months ended September 30, 2007:			Southwest		Northeast		Gulf Coast		Total
Revenue			$	351,599	$	181,117	$	57,626	$	590,342
Operating expenses:
	Purchased product costs			225,136		129,597		—		354,733
	Facility expenses			31,287		12,127		5,336		48,750
		Operating income before items not allocated to segments	$	95,176	$	39,393	$	52,290	$	186,859
	Capital Expenditures		$	220,533	$	4,202	$	4,364	$	229,099

38

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

21. Segment Information (Continued)

        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 nine months ended September 30, 2008 and 2007:

			Nine months ended September 30,
			2008			2007
Total segment revenue			$	866,760		$	590,342
	Derivative loss not allocated to segments			(96,030	)		(52,208	)
		Total revenue	$	770,730		$	538,134
Operating income before items not allocated to segments			$	312,322		$	186,859
	Derivative loss not allocated to segments			(85,905	)		(71,717	)
	Compensation expense included in facility expenses not allocated to segments			(950	)		—
	Selling, general and administrative expenses			(54,406	)		(50,545	)
	Depreciation			(48,533	)		(28,632	)
	Amortization of intangible assets			(28,050	)		(12,504	)
	Loss on disposal of property, plant and equipment			(9	)		(383	)
	Accretion of asset retirement obligations			(97	)		(85	)
	Impairment of long-lived assets			(5,009	)		(356	)
		Income from operations		89,363			22,637
	Earnings from unconsolidated affiliates			1,932			4,687
	Interest income			3,597			3,923
	Interest expense			(47,527	)		(28,670	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(7,287	)		(2,222	)
	Miscellaneous income			1,043			252
		Income before non-controlling interest in net income of consolidated subsidiaries and provision for income tax	$	41,121		$	607

39

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

21. Segment Information (Continued)

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

As of September 30, 2008:		Southwest		Northeast		Gulf Coast		Total
Total segment assets		$	1,416,583	$	335,016	$	586,313	$	2,337,912
Assets not allocated to segments:
	Certain cash and cash equivalents								101,144
	Fair value of derivatives								47,547
	Investment in unconsolidated affiliates								82,235
	Other(1)								22,328
								$	2,591,166

(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
	Investment in unconsolidated affiliates								58,709
	Other(1)								50,020
								$	1,524,695

(1)

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

40

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 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 redemption and merger and related subsequent events.

        The Merger offers the following advantages:

•

eliminates 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;

•

enhances the Partnership's ability to compete for new acquisitions;

•

improves 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 reduces 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 redemption and merger, we expect the cash available to distribute to common unitholders to increase in total and on a per common unit basis.

41

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 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.

42

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

		Three months ended September 30,					Nine months ended September 30,
		2008			2007		2008		2007
Revenue		$	303,560		$	199,934	$	866,760	$	590,342
Purchased product costs			171,539			107,609		479,747		354,733
	Net operating margin		132,021			92,325		387,013		235,609
Facility expenses			28,213			18,869		75,641		48,750
Total derivative (gain) loss			(193,489	)		38,591		85,905		71,717
Selling, general and administrative expenses			15,331			11,164		54,406		50,545
Depreciation			17,510			11,133		48,533		28,632
Amortization of intangible assets			10,732			4,168		28,050		12,504
Loss on disposal of property, plant and equipment			6			229		9		383
Accretion of asset retirement obligations			32			30		97		85
Impairment of long-lived assets			—			356		5,009		356
	Income from operations	$	253,686		$	7,785	$	89,363	$	22,637

Seasonality

        Our Northeast segment 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 generally expect our Northeast segment's volume to 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

43

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. Due to current market and financial conditions, we have seen decreases in natural gas, condensate and NGL prices, and it is uncertain if these declines will continue in the future.

•

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, including current market and financial conditions which have increased the risk of volatility in oil, natural gas and NGL prices. Any change in mix will influence our long-term financial results.

        As of September 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.

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•

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

•

Approximately 40 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 nine months ended September 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	%		35	%		18	%		38	%		100	%
Net operating margin		21	%		34	%		7	%		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.

        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 25%, 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

45

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(1)	Gathering systems	Oklahoma	$	41.3	July 31, 2008
Centrahoma Processing, LLC(2)	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(3)	Gas processing and fractionation facility	Corpus Christi, TX		398.8	November 1, 2005
Starfish(4)	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)

Includes a 50% operating interest in Wirth Gathering, a general partnership (See Note 4 to the Condensed Consolidated Financial Statements).

(2)

Represents a 40% non-controlling interest (see Note 10 to the Condensed Consolidated Financial Statements).

(3)

Consideration includes $35.5 million in cash acquired.

(4)

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 net income of $186.5 million for the three months ended September 30, 2008, compared to net loss of $7.5 million for three months ended September 30, 2007. We also reported net income of $27.9 million for the nine months ended September 30, 2008, compared to a net loss of $13.8 million for the nine months ended September 30, 2007.

        Contributing factors to the $194.0 million change in net income for the three months ended September 30, 2008, compared to the same period in 2007 were:

•

Derivative gains were $193.5 million for the three months ended September 30, 2008, compared to derivative losses of $38.6 million during the same period in 2007. The change of $232.1 million is due mainly to the decline in crude oil prices during the three months ended September 30, 2008, compared to the same period in 2007. Mark-to-market adjustments resulted in a $239.4 million decrease in unrealized loss, which was partially offset by an increase in realized losses from settlements of $7.3 million. Realized losses were $14.8 million for the three months ended September 30, 2008, compared to $7.5 million during the same period in 2007.

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•

The provision for income tax expense was $48.1 million for the three months ended September 30, 2008, compared to a $7.9 million income tax benefit for the same period in 2007. The increase of $56.0 million is due mainly to the significantly higher net income reported for the third quarter of 2008. Refer to Note 14 in the accompanying Condensed Consolidated Financial Statements for a further discussion of the significant changes in the provision for income tax.

•

In the Southwest segment, operating income before items not allocated to segments increased $16.0 million for the three months ended September 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 $13.3 million for the three months ended September 30, 2008, compared to the same period in 2007, due mainly to higher prices for NGLs and an increase in gallons sold.

•

Depreciation and amortization increased $12.9 million for the three months ended September 30, 2008, compared to the same period in 2007. Approximately $9.2 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 increased $8.7 million for the three months ended September 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 funds for future capital projects.

•

The non-controlling interest in net income of consolidated subsidiary decreased to approximately $0.1 million during the three months ended September 30, 2008, compared to $15.1 million for the same period in 2007 as a result of the Merger.

Cash Distributions

        Our quarterly cash distribution of $0.64 per common unit for the quarter ended September 30, 2008 was declared on October 22, 2008. This distribution is an increase of $0.01 per unit over the second quarter 2008 distribution.

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Operating Data

			Three months ended September 30,							Nine months ended September 30,
			2008		2007		% Change			2008		2007		% Change
Southwest
	East Texas
		Gathering systems throughput (Mcf/d)		441,800		421,000		4.9	%		431,700		410,000		5.3	%
		NGL product sales (gallons)		49,422,700		46,262,000		6.8	%		140,777,800		132,536,000		6.2	%
	Oklahoma
		Foss Lake gathering system throughput (Mcf/d)		94,200		108,000		(12.8	)%		97,800		102,000		(4.1	)%
		Grimes gathering system throughput (Mcf/d)		13,400		11,000		21.8	%		13,400		12,000		11.7	%
		Arapaho NGL product sales (gallons)		20,327,200		22,409,000		(9.3	)%		62,487,300		65,166,000		(4.1	)%
		Woodford gathering system throughput (Mcf/d)		282,500		130,000		117.3	%		247,000		95,000		160.0	%
	Other Southwest
		Appleby gathering system throughput (Mcf/d)		58,200		58,000		0.3	%		60,700		55,000		10.4	%
		Other gathering systems throughput (Mcf/d)		12,000		6,900		73.9	%		11,100		9,200		20.7	%
Northeast
	Appalachia(1)
		Keep-whole sales (gallons)		27,482,700		20,620,000		33.3	%		96,335,000		89,301,000		7.9	%
		Percent-of-proceeds sales (gallons)		13,772,300		11,172,000		23.3	%		35,142,100		33,219,000		5.8	%
		Total NGL product sales (gallons)(2)		41,255,000		31,792,000		29.8	%		131,477,100		122,520,000		7.3	%
	Michigan
		Natural gas processed for a fee (Mcf/d)		3,900		4,900		(20.4	)%		3,100		5,700		(45.6	)%
		NGL product sales (gallons)		504,800		963,000		(47.6	)%		1,728,800		3,153,000		(45.2	)%
		Crude oil transported for a fee (Bbl/d)		13,000		13,800		(5.8	)%		13,500		14,100		(4.3	)%
Gulf Coast
		Refinery off-gas processed (Mcf/d)		120,100		124,500		(3.5	)%		123,400		119,000		3.7	%
		Liquids fractionated (Bbl/d)		24,200		30,700		(21.2	)%		24,700		26,600		(7.1	)%

(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 21 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 we transport volumes for a fee.

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•

Oklahoma.  We own the Foss Lake natural gas gathering system and the Arapaho I and II natural gas processing plants, all located in Roger Mills, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. All of the gathered gas ultimately is compressed and delivered to the processing plant. Under a new agreement with Newfield Exploration Mid-Continent Inc., we will construct a 60-mile pipeline from our Foss Lake system to the Granite Wash formation in the Texas panhandle and build extensive new gathering and compression infrastructure in the area. We also own the Grimes gathering system, which is located in Roger Mills and Beckham Counties in western Oklahoma. In addition, we own a natural gas gathering system in the Woodford Shale play in the Arkoma basin of southeastern Oklahoma. Approximately 80% of our current volumes associated with our existing Oklahoma assets are derived from gathering contracts and approximately 20% are derived from purchase agreements. In July 2008, we acquired a subsidiary of PetroQuest Energy, LLC ("PetroQuest") that owns natural gas gathering assets located primarily in Pittsburg County in southeast Oklahoma. Also, in May 2008, we announced that we had increased our ownership interest in Centrahoma Processing LLC ("Centrahoma"), from 20% to 40%.

•

Other Southwest.  We own a number of natural gas gathering systems in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the natural gas produced from fields adjacent to our gathering systems. 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.

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. We are also constructing and will operate natural gas gathering systems and processing facilities associated with the Marcellus Shale acreage controlled by Range Resources Corporation ("Range"). In October 2008, we began operations in the Marcellus Shale utilizing a leased mechanical refrigeration plant with a capacity of 30 MMcf/d. This plant will operate until the two planned cryogenic processing facilities are completed. One of the cryogenic processing facilities with a capacity of 30 MMcf/d is expected to be in service at the end the first quarter of 2009. The second cryogenic facility with a capacity of 120 MMcf/d is expected to be in service by the end of 2009 or early 2010. We also announced our intentions to jointly develop several gas natural gathering and processing projects with Columbia Gas Transmission Corp. ("Columbia"), a division of NiSource Inc., in Pennsylvania and West Virginia.

•

Michigan.  We own and operate a crude oil pipeline in Michigan as well as a natural gas gathering system in Manistee County, Michigan.

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 steam methane reformer facility 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.

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        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 nine months ended September 30, 2008:

	Southwest			Northeast			Gulf Coast			Total
Revenue		62	%		29	%		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, a joint venture with Enbridge Offshore Pipelines LLC that is accounted for using the equity method. The financial results of Starfish are included in Earnings from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations and are not included in the results of our Gulf Coast segment. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility. All of these assets are located in the Gulf of Mexico or southwestern Louisiana.

         Centrahoma.    On March 1, 2008, we acquired a 20% interest in 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 September 30, 2008, compared to three months ended September 30, 2007

        Items belowIncome from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any unrealized gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The tables below present information about operating income for the reported segments for the three months ended September 30, 2008 and 2007.

Southwest

	Three months ended September 30,
	2008		2007		$ Change		% Change
	(in thousands)
Revenue	$	192,675	$	125,242	$	67,433		54	%
Operating expenses:
Purchased product costs		120,208		74,674		45,534		61	%
Facility expenses		16,670		10,797		5,873		54	%
Total operating expenses before items not allocated to segments		136,878		85,471		51,407		60	%
Operating income before items not allocated to segments	$	55,797	$	39,771	$	16,026		40	%

         Revenue.    Revenue increased for the three months ended September 30, 2008 compared to the same period in 2007 due primarily to an increase in volumes and higher pricing in most areas of the segment. Revenue in East Texas increased $31.8 million from the sale of greater NGL and condensate volumes at higher prices. Additionally, continued expansion in the Woodford gathering system and the start of gas processing operations in this area increased revenue approximately $22.9 million. Revenue from Other Southwest areas increased approximately $15.5 million due to higher prices and increased

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volumes of approximately 5,300 Mcf/d in the gathering systems. Revenue from the Foss Lake region decreased approximately $2.7 million as the impact of higher prices was offset by lower volumes.

         Purchased Product Costs.    Purchased product costs increased during the three months ended September 30, 2008, relative to the same period in 2007 due primarily to the increased NGL purchases in East Texas related 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 during the three months ended September 30, 2008, compared to the same period in 2007 due primarily to the expanded operations for the Woodford gathering system.

        Operating results for the three months ended September 30, 2008 were adversely impacted by business interruptions caused by Hurricane Ike. Management estimates that the financial impact was an approximate $2.6 million reduction of operating income.

Northeast

	Three months ended September 30,
	2008		2007		$ Change		% Change
	(in thousands)
Revenue	$	82,418	$	49,413	$	33,005		67	%
Operating expenses:
Purchased product costs		51,331		32,935		18,396		56	%
Facility expenses		6,172		4,818		1,354		28	%
Total operating expenses before items not allocated to segments		57,503		37,753		19,750		52	%
Operating income before items not allocated to segments	$	24,915	$	11,660	$	13,255		114	%

         Revenue.    Revenue increased during the three months ended September 30, 2008 compared to the same period in 2007 due mainly to higher prices and increased volumes of NGLs sold from the Appalachia region. The increase in volumes resulted from upgrades to our processing facilities in this area and increased volumes from a large producer due to expansion of the contracted volumes.

         Purchased Product Costs.    Purchased product costs increased during the three months ended September 30, 2008 compared to the same period in 2007 due to the higher prices for the natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area and an increase in the volumes purchased. The increase in purchased product costs was partially offset by a $1.2 million decrease in trucking expenses resulting from a change in contractual terms with a producer.

         Facility Expenses.    The increase in facility expenses for the three months ended September 30, 2008, relative to the same period in 2007 is due primarily to increases in repairs and maintenance expense and labor and benefits expense to support the increased level of operations in the Appalachia region.

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Gulf Coast

	Three months ended September 30,
	2008		2007		$ Change		% Change
	(in thousands)
Revenue	$	28,467	$	25,279	$	3,188		13	%
Operating Expenses:
Facility expenses		5,085		3,254		1,831		56	%
Total operating expenses before items not allocated to segments		5,085		3,254		1,831		56	%
Operating income before items not allocated to segments	$	23,382	$	22,025	$	1,357		6	%

         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 during the three months ended September 30, 2008, relative to the same period in 2007 due mainly to higher pricing. The pricing increases were partially offset by lower volumes related to temporary issues at the producers' refineries and 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 $5.2 million of revenue in the quarter, compared to $2.6 million of pentanes in the third quarter of 2007. Historically, pentanes had to be stored and were sold seasonally. However, with the completion of a new pentane hydrotreater in March of 2008, the quality of the pentanes has been improved and can be sold on a recurring basis as they are produced. The increases in revenue were partially offset by an approximate $1.0 million reduction of revenue as a result of business interruptions caused by Hurricane Ike.

         Facility Expenses.    Facility expenses increased during the three months ended September 30, 2008, relative to the same period in 2007 due to increased electricity expenses. The increase related to a new contract effective 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 September 30, 2008 and 2007. The ensuing items listed below theTotal segment revenue andOperating income lines are

52

not allocated to business segments as management does not consider these items allocable to any individual segment.

			Three months ended September 30,
			2008			2007			$ Change			% Change
			(in thousands)
Total segment revenue			$	303,560		$	199,934		$	103,626			52	%
	Derivative gain (loss) not allocated to segments			262,811			(24,386	)		287,197			(1,178	)%
		Total revenue	$	566,371		$	175,548		$	390,823			223	%
Operating income before items not allocated to segments			$	104,094		$	73,456		$	30,638			42	%
	Derivative gain (loss) not allocated to segments			193,489			(38,591	)		232,080			(601	)%
	Compensation expense included in facility expenses not allocated to segments			(286	)		—			(286	)		N/A
	Selling, general and administrative expenses			(15,331	)		(11,164	)		(4,167	)		37	%
	Depreciation			(17,510	)		(11,133	)		(6,377	)		57	%
	Amortization of intangible assets			(10,732	)		(4,168	)		(6,564	)		157	%
	Loss on disposal of property, plant and equipment			(6	)		(229	)		223			(97	)%
	Accretion of asset retirement obligations			(32	)		(30	)		(2	)		7	%
	Impairment of long-lived assets			—			(356	)		356			(100	)%
		Income from operations		253,686			7,785			245,901			3,159	%
	(Loss) earnings from unconsolidated affiliates			(196	)		1,264			(1,460	)		(116	)%
	Interest income			1,421			403			1,018			253	%
	Interest expense			(18,928	)		(10,202	)		(8,726	)		86	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(1,080	)		(771	)		(309	)		40	%
	Miscellaneous (expense) income			(99	)		1,319			(1,418	)		(108	)%
	Income (loss) before non-controlling interest in net income of consolidated subsidiaries and provision for income tax		$	234,804		$	(202	)	$	235,006			(116,340	)%

         Derivative Gain (Loss).    Derivative gains were $193.5 million for the three months ended September 30, 2008, compared to derivative losses of $38.6 million during the same period in 2007. The change of $232.1 million is primarily attributable to the third quarter decline in crude oil prices compared to a small increase in crude oil prices in the same period in 2007. Mark-to-market adjustments resulted in a $239.4 million change in unrealized gain (loss). Settlements of our derivative instruments resulted in a $7.3 million increase in realized losses, when comparing 2008 to 2007 results.

         Selling, General and Administrative Expenses.    Selling, general and administrative expenses increased during the three months ended September 30, 2008 compared to the same period in 2007 primarily due to a $2.7 million increase in compensation expense related to phantom unit awards. Compensation expense increased an additional $1.1 million due to a higher wage base and larger employee group in 2008.

         Depreciation and Amortization of Intangible Assets.    Depreciation and amortization expense increased during the three months ended September 30, 2008 compared to the same period in 2007 due to a $9.2 million increase caused by the step-up in value of property, plant, and equipment and intangible assets as a result of the Merger. The remainder is due to depreciation on additional projects completed the last quarter of 2007 and the first nine months of 2008.

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         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. which is accounted for using the equity method. The decrease in our earnings from unconsolidated affiliates is due mainly to the damage and business interruption caused by Hurricane Ike in September 2008 (refer toMatters Impacting Future Results for additional discussion).

         Interest Income.    Interest income increased during the three months ended September 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 during the three months ended September 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 expense was $0.1 million during the three months ended September 30, 2008, compared to miscellaneous income of $1.3 million during the same period in 2007. In the third quarter of 2007, we recognized approximately $1.4 million of insurance recoveries related to damages and business interruption caused by Hurricanes Rita and Katrina in 2005. Final settlement of these insurance claims occurred in the second quarter of 2008. Therefore no additional insurance recoveries were recognized in the third quarter of 2008.

         Non-controlling Interest in Net Income of Consolidated Subsidiaries.    The non-controlling interest in net income of consolidated subsidiaries decreased to approximately $0.1 million during the three months ended September 30, 2008 compared to $15.1 million during the same period 2007. The amount recorded in 2008 relates primarily to our 50% controlling operating interest in Wirth Gathering, a general partnership, that was acquired in July 2008. The amount recorded in 2007 relates to the non-controlling interest in the Partnership that longer exists in 2008 due to the Merger.

         Provision for Income Tax.    Refer to Note 14 in the accompanying Condensed Consolidated Financial Statements for a discussion of the significant changes in the provision for income tax.

Nine months ended September 30, 2008, compared to nine months ended September 30, 2007

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

Southwest

	Nine months ended September 30,
	2008		2007		$ Change		% Change
	(in thousands)
Revenue	$	536,563	$	351,599	$	184,964		53	%
Operating expenses:
Purchased product costs		322,370		225,136		97,234		43	%
Facility expenses		45,189		31,287		13,902		44	%
Total operating expenses before items not allocated to segments		367,559		256,423		111,136		43	%
Operating income before items not allocated to segments	$	169,004	$	95,176	$	73,828		78	%

         Revenue.    Revenue increased for the nine months ended September 30, 2008 compared to the same period 2007 due primarily to an increase in volumes and higher pricing in most areas of the segment. Revenue in East Texas increased $89.7 million from the sale of greater NGL and condensate

54

volumes at higher prices. Additionally, continued expansion in the Woodford gathering system and the start of gas processing operations in this area increased revenue approximately $51.0 million. Revenue from Other Southwest areas increased approximately $38.5 million due to higher prices and increased volumes of approximately 7,600 Mcf/d in the gathering systems. Revenue from the Foss Lake region increased by $5.8 million as the impact of higher prices was offset by lower volumes.

         Purchased Product Costs.    Purchased product costs increased during the nine months ended September 30, 2008, relative to the same period in 2007 due primarily to the increased NGL purchases in East Texas related 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 during the nine months ended September 30, 2008, relative to the same period in 2007 due to the increased operations for the Woodford gathering system and expanded operations in most areas of the Southwest segment.

Northeast

	Nine months ended September 30,
	2008		2007		$ Change		% Change
	(in thousands)
Revenue	$	251,115	$	181,117	$	69,998		39	%
Operating expenses:
Purchased product costs		157,377		129,597		27,780		21	%
Facility expenses		16,161		12,127		4,034		33	%
Total operating expenses before items not allocated to segments		173,538		141,724		31,814		22	%
Operating income before items not allocated to segments	$	77,577	$	39,393	$	38,184		97	%

         Revenue.    Revenue increased during the nine months ended September 30, 2008 compared to the same period in 2007 due mainly to higher prices and increased volumes of NGLs sold from the Appalachia region. The increase in volumes resulted from upgrades to our processing facilities in this area and increased volumes from a large producer due to expansion of the contracted volumes.

         Purchased Product Costs.    The increase in purchased product cost in 2008 compared to 2007 is mainly due to higher prices for natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area and an increase in the volumes of natural gas purchased. The increase in purchased product costs was partially offset by a $3.0 million decrease in trucking expenses resulting from a change in contractual terms with a producer.

         Facility Expenses.    The increase in facility expenses for the nine months ended September 30, 2008, relative to the same period in 2007 is due primarily to increases in plant fuel costs, repairs and maintenance expense and labor and benefits expense to support the increased level of operations in the Appalachia region.

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Gulf Coast

	Nine months ended September 30,
	2008		2007		$ Change		% Change
	(in thousands)
Revenue	$	79,082	$	57,626	$	21,456		37	%
Operating expenses:
Facility expenses		13,341		5,336		8,005		150	%
Total operating expenses before items not allocated to segments		13,341		5,336		8,005		150	%
Operating income before items not allocated to segments	$	65,741	$	52,290	$	13,451		26	%

         Revenue.    Revenue increased during the nine months ended September 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 sale of pentanes generated $8.2 million of revenue for the nine months ended 2008, compared to $2.6 million for the same period in 2007. Historically, pentanes had to be stored and were sold seasonally. However with the completion of a new pentane hydrotreater in March of 2008, the quality of the pentanes has been improved, and they can be sold on a recurring basis as they are produced.

         Facility Expenses.    Facility expenses increased during the nine months ended September 30, 2008, relative to the same period in 2007 due partially to a utility refund of $3.6 million from a rate case concluded in the first quarter of 2007. Excluding the refund, facility expenses were $4.4 million higher 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. Higher labor and benefits costs also contributed to the increase in facility expenses.

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 nine months ended September 30, 2008 and 2007. The ensuing items listed below theTotal segment revenue andOperating income lines are

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not allocated to business segments as management does not consider these items allocable to any individual segment.

			Nine months ended September 30,
			2008			2007			$ Change			% Change
			(in thousands)
Total segment revenue			$	866,760		$	590,342		$	276,418			47	%
	Derivative loss not allocated to segments			(96,030	)		(52,208	)		(43,822	)		84	%
		Total revenue	$	770,730		$	538,134		$	232,596			43	%
Operating income before items not allocated to segments			$	312,322		$	186,859		$	125,463			67	%
	Derivative loss not allocated to segments			(85,905	)		(71,717	)		(14,188	)		20	%
	Compensation expense included in facility expenses not allocated to segments			(950	)		—			(950	)		N/A
	Selling, general and administrative expenses			(54,406	)		(50,545	)		(3,861	)		8	%
	Depreciation			(48,533	)		(28,632	)		(19,901	)		70	%
	Amortization of intangible assets			(28,050	)		(12,504	)		(15,546	)		124	%
	Loss on disposal of property, plant and equipment			(9	)		(383	)		374			(98	)%
	Accretion of asset retirement obligations			(97	)		(85	)		(12	)		14	%
	Impairment of long-lived assets			(5,009	)		(356	)		(4,653	)		1,307	%
		Income from operations		89,363			22,637			66,726			295	%
	Earnings from unconsolidated affiliates			1,932			4,687			(2,755	)		(59	)%
	Interest income			3,597			3,923			(326	)		(8	)%
	Interest expense			(47,527	)		(28,670	)		(18,857	)		66	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(7,287	)		(2,222	)		(5,065	)		228	%
	Miscellaneous income			1,043			252			791			314	%
	Income before non-controlling interest in net income of consolidated subsidiaries and provision for income tax		$	41,121		$	607		$	40,514			6,674	%

         Derivative Loss.    Loss from derivative instruments increased during the nine months ended September 30, 2008, relative to the same period in 2007. Mark-to-market adjustments resulted in a $30.9 million decrease in unrealized loss. Settlements of our derivative instruments resulted in a $45.1 million increase in realized losses, when comparing 2008 to 2007 results. The increased derivative loss is primarily attributable to higher relative crude oil prices in 2008 compared to 2007.

         Selling, General and Administrative Expenses.    Selling, general and administrative expenses increased during the nine months ended September 30, 2008, relative to the same period in 2007 due primarily to a $7.1 million increase in compensation expenses related to phantom unit awards. Labor and benefits expense increased by approximately $3.0 million related to a higher wage and benefit base in 2008. Higher letter of credit fees, novation expenses, and professional consulting services also contributed to the increase. The increases in costs were partially offset by a decrease in compensation expense related to the Participation Plan of $7.8 million and a decrease in Merger related expenses of $1.4 million.

         Depreciation and Amortization of Intangible Assets.    Depreciation and amortization expense increased during the three months ended September 30, 2008 compared to the same period in 2007 due to an $18.7 million increase caused by the step-up in value of property, plant, and equipment and intangible assets as a result of the Merger. The remainder is due to depreciation on additional projects completed the last quarter of 2007 and the first nine months of 2008.

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         Impairment of Long-Lived Assets.    During the nine months ended September 30, 2008, we recognized an impairment charge of $5.0 million related to certain gas-gathering assets in the Northeast segment. During the nine months ended September 30, 2007, we recognized an impairment charge of $0.4 million related to assets in the Southwest segment. Refer to Note 12 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. which is accounted for using the equity method,. The decrease in our earnings from unconsolidated affiliates for the nine months ended September 30, 2008 compared to the same period in 2007 is due mainly to the damage and business interruption caused by Hurricane Ike in September 2008 (refer toMatters Impacting Future Results for additional discussion).

         Interest Income.    Interest income decreased during the nine months ended September 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 during the nine months ended September 30, 2008, relative to the same period in 2007, primarily due to increased borrowings in 2008 to fund the Merger and to raise funds for future acquisitions and growth projects.

         Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount increased during the nine months ended September 30, 2008, compared to the same period in 2007 due mainly to the $4.2 million write-off of financing costs related to a term loan that was repaid in April 2008.

         Non-controlling Interest in Net Income of Consolidated Subsidiaries.    The non-controlling interest in net income of consolidated subsidiaries decreased during the nine months ended September 30, 2008, relative to the same period in 2007 due to the fact that there was no longer a non-controlling interest in the Partnership after the Merger was completed on February 21, 2008. The 50% non-controlling interest in the earnings of Wirth Gathering, which was acquired in July 2008, is not material for the nine months ended September 30, 2008.

         Provision for Income Tax.    The total provision for income taxes for the nine months ended September 30, 2008 was $16.5 million. Refer to Note 14 in the accompanying Condensed Consolidated Financial Statements for a discussion of the significant changes in the provision.

        The current provision for income taxes was $22.9 million for the nine months ended September 30, 2008. Approximately $21.9 million is attributable to MarkWest Hydrocarbon, Inc. Of this amount, $15.6 million is attributable to MarkWest Hydrocarbon's ownership of Class A units, and the remaining $6.3 million is related to the Corporation's NGL marketing business. The remaining $1.0 million is related to taxes payable by the Partnership associated with the Texas Margin tax and Michigan Business Taxes.

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Liquidity and Capital Resources

        Our primary strategy is to expand our asset base through organic growth and expansion projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit. In 2007, we spent approximately $312 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 will spend approximately $565 million to fund identified organic growth and expansion projects that have been approved by our board of directors, including the third-party acquisitions noted above and our investment in Centrahoma. As of September 30, 2008, we estimate that we will spend another $185 million in the fourth quarter of 2008, out of the $565 million to be spent in 2008. We also estimate that we will spend $2 million for maintenance capital in the fourth quarter of 2008.

        The 2009 capital plan includes approximately $300 million of capital expenditures for board approved growth projects, plus $5 million to $10 million for maintenance capital. Growth capital includes expenditures made to expand the existing operating capacity, increase the efficiency of our existing assets, or facilitate an increase in volumes within our operations. Growth capital includes expenditures for construction or third-party acquisition. Maintenance capital includes capital expenditures made to maintain our operating capacity and asset base. Maintenance capital does not include costs associated with new well connections. In addition to the planned capital expenditures in 2009, we expect to receive capital calls in 2008 of approximately $5 million to $7 million within our Starfish joint venture for the cost to repair damages to the on-shore and off-shore facilities caused by Hurricane Ike. We expect to file insurance claims and recover a portion of those costs (see further discussion in theMatters Impacting Future Results).

        Our primary sources of liquidity to meet operating expenses and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private. All expenditures on board approved 2008 and 2009 capital projects will be funded with cash flow from operations, current cash balances, and our current borrowing capacity under our revolving credit facility. However, we believe that it will be necessary to raise additional capital in order to finance incremental growth projects beyond those that are currently approved by the board.

        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 total borrowing capacity of the revolving credit facility could be increased to $550.0 million, subject to the approval of participating bank group. However, in light of the current conditions in the financial sector, there is no guarantee that this approval would be granted. 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 October 31, 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; however, there is no certainty that the members of our bank group will continue to participate and in such case, a portion of our available credit could be used for derivative instruments instead of future growth.

        On April 14, 2008, we completed a public offering 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

59

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 13 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 October 31, 2008, we had no borrowings outstanding under the revolving credit facility and had approximately $281.2 million available for borrowing, with $68.8 million of letters of credit outstanding. As of October 31, 2008, we had approximately $18.9 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, has two other series of senior notes outstanding as of September 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 13 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. The current global economic uncertainty has had a significant adverse impact on the availability of capital funding. Additionally, commodity prices have continued to decline sharply since the end of our third fiscal quarter. Our future operating performance could be negatively impacted if these conditions do not improve or continue to deteriorate.

Cash Flow

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

	Nine months ended September 30,
	2008			2007
Net cash provided by operating activities	$	216,132		$	96,535
Net cash flows used in investing activities		(648,794	)		(227,899	)
Net cash flows provided by financing activities		499,880			138,954

        Net cash provided by operating activities increased $119.6 million during the nine months ended September 30, 2008, compared to the corresponding period in 2007. The change primarily 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 $420.9 million during the nine months ended September 30, 2008, compared to the corresponding period in 2007. This increase was primarily due to

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cash paid as consideration in the Merger of $269.9 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 $385.2 million of expansion capital, including equity investments and the acquisition of PQ Assets in 2008.

        Net cash provided by financing activities increased $360.9 million during the nine months ended September 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 funds 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 September 30, 2008, the Partnership's purchase obligations for the remainder of 2008 were $135.7 million compared to our 2008 obligations of $88.1 million as of December 31, 2007. Purchase obligations represent purchase orders and contracts for property, plant and equipment. The increase is related to a significant number of growth projects initiated in 2008. Other than this increase in purchase obligations and the issuance of additional long-term debt (as discussed further in Note 13 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 13 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 16 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 September 30, 2008 and 2007, our results included compensation expense of zero and $(0.5) million, respectively, related to the Participation Plan. For the nine months ended September 30, 2008 and 2007, our results included compensation expense of $5.5 million and $13.3 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 16 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

61

financial performance goals established by the Board of Directors. The maximum of the range assumes such conditions will be achieved. Compensation expense recorded for the performance-based units expected to vest was approximately $2.9 million for the nine months ended September 30, 2008. The timing of the remainder of the expense cannot be estimated.

        On March 1, 2008, we acquired a 20% interest in 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 less than $0.1 million for both the three and nine months ended September 30, 2008. We expect Centrahoma's income, and our portion thereof, to increase as the processing capabilities of the plants have increased in the fourth quarter of 2008.

        In June 2008, we announced an agreement with Range to construct and operate natural gas gathering pipelines and processing facilities associated with Range's Marcellus Shale acreage in the Appalachian basin. Our services under this agreement are primarily percent-of-liquids arrangements. By the end of 2008, we expect to have installed high-pressure gathering lines, up to eight new compressor stations, and to have placed into service 60 MMcf/d of processing capacity. By the end of 2009, we expect to install an additional 120 MMcf/d processing facility.

        In July 2008, we acquired PQ Gathering Assets, LLC, a subsidiary of PetroQuest that owns natural gas gathering assets located primarily in Pittsburg County in southeast Oklahoma for $41.3 million. The acquisition also includes a 50% controlling operating interest in Wirth Gathering, a general partnership. These gathering systems currently support approximately 45 MMcf/d of natural gas service wells. The PetroQuest natural gas gathering assets are located adjacent to, and will be fully integrated with, our existing Woodford Shale gathering system. Our contracts for these systems are primarily fee-based arrangements.

        In August 2008, we announced our intention to jointly develop several natural gas gathering and processing projects with Columbia Gas, a division of NiSource Inc., to support increased production volumes in the northern West Virginia and western Pennsylvania areas of the Appalachian basin. MarkWest and Columbia Gas are in discussions with several interested natural gas producers to provide new gathering and gas processing services in association with Columbia Gas' existing Majorsville, WV compressor station. Several existing Columbia pipelines in Washington and Greene counties in Pennsylvania and Marshall and Wetzel counties in West Virginia are available to serve as the backbone of the gathering system connecting with our proposed processing plant at Majorsville. We could begin processing a portion of the production from these pipelines as early as January 2009 and may increase volumes during 2009 and 2010.

        In October 2008, we announced our intention, in collaboration with Columbia, to jointly expand natural gas gathering and processing services to support the increased production volumes in the Appalachian basin of central West Virginia. Columbia and MarkWest are in discussions with several natural gas producers regarding plans to provide new gathering and processing services near Columbia Gas' Cobb aggregation system in Kanawha, Jackson and Roane counties of West Virginia. The additional volumes will be processed at our existing Cobb processing facility, and the recovered liquids will be fractionated at our existing Siloam facility.

        In September 2008, Hurricane Ike caused wind and water damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions, including damage to several onshore and offshore facilities of Starfish, our unconsolidated affiliate. Due to the damage in the region, the operations of Starfish have been shut down since the hurricane impacted the area in the middle of September. Until necessary repairs are completed, Starfish will not be able to fully return to normal operations, which will have a

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continuing impact on our net income. We are still in the process of determining the full impact of the hurricane on our 2008 results; however, we estimate it will reduce cash available for distribution by approximately $8 million to $10 million for the remainder of 2008 into early 2009. The determination of the full effect of the hurricane is subject to a number of factors including ongoing damage assessments, disclosures by operators of interconnecting production and processing facilities, and discussions with insurance carriers for insurance recovery for damages and business interruption.

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 nine months ended September 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 5 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

63

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 5 to the accompanying Notes to the Condensed Consolidated Financial Statements.

Merger 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 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.

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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;

•

The estimated fair value of the investment is less than its carrying amount; or

•

Other operational or external factors 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 nine months ended September 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 accounting. As of September 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, is 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 relate to a contract utilized to hedge electricity costs.

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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.

        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 market purchases to meet commitments,

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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 and keep-whole positions at September 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		3,329	$	66.99	$	78.60	$	(7,265	)
2009		3,425		67.50		77.83		(34,852	)
2010 (Apr—Dec)		2,010		66.52		74.71		(16,782	)
2011		1,706		80.00		104.50		(7,062	)

WTI Crude Puts	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		Fair Value (in thousands)
2008		3,651	$	80.00	$	359
2009		2,413		80.00		4,524
2010		1,191		80.00		3,087
2011		1,818		80.00		4,910

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2008		150	$	69.76	$	(421	)
2009		1,454		119.50		8,764
2010 (Jan—Sep)		2,461		92.98		(9,969	)
2011		1,719		117.83		7,047

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2009		9,770	$	8.38	$	(4,496	)
2010		8,628		8.65		(2,419	)
2011		11,430		8.51		(2,799	)

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

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2008		2,648	$	52.92	$	(11,498	)
2009		3,374		66.02		(43,729	)
2010		2,428		70.25		(28,698	)
2011		3,027		87.66		(17,671	)
2012 (Jan)		2,142		91.50		(818	)

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Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2008		7,030	$	9.42	$	(1,100	)
2009		18,934		8.11		1,819
2010		10,806		8.41		1,173
2011		14,662		8.88		(263	)

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2008		34,260	$	1.07	$	(1,203	)

Normal Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2008		29,465	$	1.70	$	178
2009		19,636		1.94		549

Iso Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2008		9,743	$	1.75	$	88
2009		6,727		1.98		203

Natural Gasoline Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2008		20,994	$	2.16	$	124
2009		13,151		2.51		430

        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 No. 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 September 30, 2008, the estimated fair value of this contract was $(9.9) 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 September 30, 2008, the estimated fair value of this contract was $(1.4) million.

        We have not entered into any derivative positions subsequent to September 30, 2008.

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 October 31, 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

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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.

Long-Term Debt	Interest Rate	Lending Limit		Due Date	Outstanding at September 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 September 30, 2008 and October 31, 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 in earnings over a 12-month period.

Item 4.    Controls and Procedures

Disclosure Controls and Procedures

        As of September 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 September 30, 2008, that have materially affected, or are reasonably likely to materially affect, the Partnership's internal control over financial reporting.

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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 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 captionedMarkWest 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. The Partnership and the Defendant insurance companies have filed briefs in connection with the appeal.

        Also related to the above referenced 2004 pipeline explosion and fire incident, MarkWest's insurance carriers, Ace Westchester Surplus Lines Insurance Company, AEGIS Insurance Services, and Co-defendant Equitable Production Company, the pipeline owner, and its separate insurance policy

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with AEGIS Insurance Services, funded the 2007 settlement of the third party personal injury and property damage plaintiffs' claims inRicky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, and Civil Action No. 05-CI-00137, and in doing so exhausted the limits of MarkWest's AEGIS policy and partially utilized proceeds from MarkWest's Ace Westchester policy, an excess insurance layer. The parties and insurers all disputed the proper allocation of insurance obligations under the respective policies and the commercial agreements between MarkWest and Equitable Production Company. In the Funding Agreement for the final settlements of the underlying personal injury and property damage actions, the various insurers and defendants reserved all rights with regard to re-allocation of insurance coverage obligations by and amongst the respective insurance policies of the parties, and agreed to an ADR process to address these issues. On April 30, 2007, Ace Westchester initiated the ADR process. The principal dispute is whether the Equitable AEGIS policy should have been obligated to share/pay more in the settlements and defense costs, which would potentially result in the Ace Westchester to be refunded the amounts it paid as its policy may never have been property triggered. A mediation, held August 20, 2008, was unsuccessful, and the matter is set for binding arbitration. The Partnership will cooperate with its insurers and vigorously defend any assertions of liability, but believes this dispute should primarily be between the insurance companies as a dispute of allocation of insurance proceeds and payments among the insurance companies, and that at this time believes that this arbitration should not have a material adverse impact on the Partnership's financial position or results of operations.

        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 theGonzales case cited above); andEsmerejilda 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 captionedJesus 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.

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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 ("Form 10-K"), except as set forth below:

         The global financial crisis may have impacts on our business and financial condition that we currently cannot predict and our ability to access the credit and capital markets on attractive terms to obtain funding for our capital projects may be limited due to the deterioration of these markets.

        The unprecedented and continued credit crisis and related turmoil in the global markets and financial systems in the third quarter, which have continued into the fourth quarter, have increased both the volatility and the amplitude of the risk associated with those risk factors identified in our Form 10-K. These events have had an impact on our yield and unit price, and may have an impact on our business and our financial condition. In particular, the cost of capital has increased substantially while the availability of funds from those markets has diminished significantly. Accordingly, our ability to access the capital markets may be restricted or be available only on unfavorable terms, which could significantly and adversely impact our ability to execute our long term organic growth projects. Limited access to the capital markets could also adversely impact our ability to otherwise take advantage of business opportunities or react to changing economic and business conditions. Ultimately we may be required to substantially reduce our future capital expenditures. This could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on the common units. The current economic situation could have an impact on our lenders, producers, or other customers, causing them to fail to meet their obligations to us, and these market conditions could also have an impact on our commodity hedging arrangements if our counterparties are unable to perform their obligations. The uncertainty and volatility of the unprecedented global financial crisis may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

        Furthermore, the current conditions of the global financial markets have contributed and recent declines in commodity prices may have contributed to a decline in our unit price and corresponding market capitalization. Continued declines in our market capitalization could result in a noncash impairment of our recorded goodwill. Continued declines in commodity prices could have an adverse impact on cash flows from operations that could result in noncash impairments of long-lived assets, as well as other-than-temporary noncash impairments of our equity method investments.

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

        None.

Item 3.    Defaults Upon Senior Securities

        None.

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

        None.

Item 5.    Other Information

        None.

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Item 6.    Exhibits

10.1*	+	Stiles/Britt Ranch Gas Gathering and Processing Agreement dated effective as of June 12, 2008 and executed August 5, 2008 between Newfield Exploration Mid-Continent Inc. and MarkWest Oklahoma Gas Company, L.L.C.
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

+

Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.

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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

Date: November 10, 2008	/s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer)
Date: November 10, 2008	/s/ NANCY K. BUESE Nancy K. Buese Senior Vice President & Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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