UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2007

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 001-14841

MARKWEST HYDROCARBON, INC.

(Exact name of registrant as specified in its charter)

Delaware		84-1352233
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202-2126

(Address of principal executive offices)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

The registrant had 12,001,209 shares of common stock, $0.01 per share par value, outstanding as of July 27, 2007.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at June 30, 2007 and December 31, 2006	3
	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2007 and 2006	4
	Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2007 and 2006	5
	Condensed Consolidated Statement of Changes in Stockholders’ Equity for the six months ended June 30, 2007	6
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and 2006	7
	Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	49
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	50
Item 4.	Submission of Matters to a Vote of Security Holders	52
Item 6.	Exhibits	53
SIGNATURES		54

Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” included later in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for an explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to “we,” “us,” “our,” “MarkWest Hydrocarbon” or the “Company” are intended to mean MarkWest Hydrocarbon, Inc., and its consolidated subsidiaries. “MarkWest Energy” or “MarkWest Energy Partners” or the “Partnership” is intended to mean MarkWest Energy Partners, L.P.

Glossary of Terms

Bbl/d		barrels per day
Btu		one British thermal unit, an energy measurement
Gal		gallons
Gal/d		gallons per day
Mcf		one thousand cubic feet of natural gas
Mcf/d		one thousand cubic feet of natural gas per day
MMBtu		one million British thermal units, an energy measurement
MMBtu/d		one million British thermal units, an energy measurement, per day
MMcf/d		one million cubic feet of natural gas per day
MTBE		methyl tertiary butyl ether
NA		not applicable
Net operating margin (a non-GAAP financial measure)		revenues less purchased product costs
NGL(s)		natural gas liquid(s), such as propane, butanes and natural gasoline

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST HYDROCARBON, INC.
Condensed Consolidated Balance Sheets
(unaudited, in thousands, except share data)

	June 30, 2007				December 31, 2006
ASSETS
Current assets:
Cash and cash equivalents		$	39,909			$	48,844
Investment securities, at fair value:
Trading		15,806				—
Available-for-sale		9,170				7,713
Receivables, net of allowances of $183 and $156, respectively		126,448				101,116
Inventories		36,345				35,261
Fair value of derivative instruments		3,523				9,938
Other current assets		26,284				15,264
Total current assets		257,485				218,136
Property, plant and equipment		833,947				662,606
Less: accumulated depreciation, depletion, amortization and impairment		(125,635		)		(108,271		)
Total property, plant and equipment, net		708,312				554,335
Other assets:
Investment in Starfish		61,474				64,240
Intangibles, net of accumulated amortization of $37,416 and $29,080 respectively		335,058				344,066
Deferred financing costs, net of accumulated amortization of $4,459 and $5,462 respectively		14,859				16,079
Deferred contract cost, net of accumulated amortization of $858 and $702, respectively		2,392				2,548
Fair value of derivative instruments		4,496				2,794
Deferred income taxes		4,000				—
Other long-term assets		1,043				1,043
Total other assets		423,322				430,770
Total assets		$	1,389,119			$	1,203,241
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	100,606			$	89,242
Accrued liabilities		86,055				55,208
Fair value of derivative instruments		18,624				7,476
Deferred income taxes		732				180
Total current liabilities		206,017				152,106
Deferred income taxes		604				9,553
Fair value of derivative instruments		22,213				1,460
Long-term debt, net of original issue discount of $2,970 and $3,135, respectively		529,030				526,865
Other long-term liabilities		44,799				30,196
Non-controlling interest in consolidated subsidiary		557,323				441,572
Commitments and contingencies (Note 13)
Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding		—				—
Common stock, par value $0.01, 20,000,000 shares authorized, 12,000,938 and 11,975,256 shares issued, respectively		120				120
Additional paid-in capital		34,288				40,266
Accumulated deficit		(7,272		)		—
Accumulated other comprehensive income, net of tax		2,008				1,103
Treasury stock, 271 and 0 shares, respectively		(11		)		—
Total stockholders’ equity		29,133				41,489
Total liabilities and stockholders’ equity		$	1,389,119			$	1,203,241

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

MARKWEST HYDROCARBON, INC.
Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per share amounts)

	Three months ended June 30,								Six months ended June 30,
	2007				2006				2007				2006
Revenue:
Revenue		$	176,893			$	186,351			$	352,290			$	427,470
Derivative loss		(13,913		)		(13,057		)		(27,822		)		(14,316		)
Total revenue		162,980				173,294				324,468				413,154
Operating expenses:
Purchased product costs		109,507				116,523				213,714				298,151
Facility expenses		18,415				14,313				30,477				27,795
Selling, general and administrative expenses		18,820				13,061				39,535				24,437
Depreciation		9,325				7,778				17,499				15,156
Amortization of intangible assets		4,168				4,027				8,336				8,043
Accretion of asset retirement obligations		28				26				55				51
Total operating expenses		160,263				155,728				309,616				373,633
Income from operations		2,717				17,566				14,852				39,521
Other income (expense):
Earnings from unconsolidated affiliates		1,656				1,228				3,423				2,173
Interest income		1,124				436				3,520				842
Interest expense		(9,054		)		(10,798		)		(18,468		)		(21,842		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)		(731		)		(859		)		(1,451		)		(1,684		)
Dividend income		217				109				339				215
Miscellaneous (expense) income		(534		)		1,517				(1,406		)		3,759
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(4,605		)		9,199				809				22,984
Non-controlling interest in net income of consolidated subsidiary		(5,562		)		(11,273		)		(9,522		)		(21,817		)
(Loss) income before income taxes		(10,167		)		(2,074		)		(8,713		)		1,167
Provision for income tax benefit (expense)		2,895				(58		)		2,398				(467		)
Net (loss) income		$	(7,272	)		$	(2,132	)		$	(6,315	)		$	700
Net (loss) income per share:
Basic		$	(0.61	)		$	(0.18	)		$	(0.53	)		$	0.06
Diluted		$	(0.61	)		$	(0.18	)		$	(0.53	)		$	0.06
Weighted average number of outstanding shares of common stock:
Basic		11,996				11,936				11,991				11,921
Diluted		11,996				11,936				11,991				12,046
Cash dividend declared per common share		$	0.32			$	0.16			$	0.62			$	0.27

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

MARKWEST HYDROCARBON, INC.
Condensed Consolidated Statements of Comprehensive Income
(unaudited, in thousands)

	Three months ended June 30,								Six months ended June 30,
	2007				2006				2007				2006
Net (loss) income		$	(7,272	)		$	(2,132	)		$	(6,315	)		$	700
Other comprehensive income:
Unrealized gain on available-for-sale securities, net of tax of $206, $56, $552 and $171, respectively.		339				94				905				287
Comprehensive (loss) income		$	(6,933	)		$	(2,038	)		$	(5,410	)		$	987

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

MARKWEST HYDROCARBON, INC.
Condensed Consolidated Statement of Changes in Stockholders’ Equity
(unaudited, in thousands)

	Shares of Common Stock		Shares of Treasury Stock			Common Stock			Additional Paid in Capital				Accumulated Deficit				Accumulated Other Comprehensive Income			Treasury Stock				Total Stockholders’ Equity
December 31, 2006		11,975		—			$	120		$	40,266			$	—			$	1,103		$	—			$	41,489
Stock option exercises		9		5			—			(22		)		—				—			136				114
Compensation expense related to restricted stock, net of registration costs		—		—			—			355				—				—			—				355
Issuance of restricted stock		17		—			—			—				—				—			—				—
Treasury stock reacquired		—		(5	)		—			147				—				—			(147		)		—
FAS 123R windfall pool under APIC		—		—			—			91				—				—			—				91
FIN 48 Adjustment		—		—			—			—				(71		)		—			—				(71		)
Net loss		—		—			—			—				(6,315		)		—			—				(6,315		)
Dividends paid		—		—			—			(6,549		)		(886		)		—			—				(7,435		)
Other comprehensive income		—		—			—			—				—				905			—				905
June 30, 2007		12,001		—			$	120		$	34,288			$	(7,272	)		$	2,008		$	(11	)		$	29,133

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

MARKWEST HYDROCARBON, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)

	Six months ended June 30,
	2007				2006
Cash flows from operating activities:
Net (loss) income		$	(6,315	)		$	700
Adjustments to reconcile net income to net cash provided by operating activities (net of acquisitions):
Depreciation		17,499				15,156
Amortization of intangible assets		8,336				8,043
Amortization of deferred financing costs and original issue discount		1,451				1,684
Accretion of asset retirement obligation		55				51
Amortization of gas contract		156				156
Restricted unit compensation expense		1,179				571
Participation Plan compensation expense		13,773				3,944
Stock option compensation expense		—				35
Restricted stock compensation expense		373				176
Non-controlling interest in net income of consolidated subsidiary		9,522				21,817
Equity in earnings of unconsolidated affiliates		(3,423		)		(2,173		)
Distributions from equity investments		6,189				—
Unrealized loss on derivative instruments		36,613				14,378
Loss (gain) on sale of property, plant and equipment		154				(421		)
Deferred income taxes		(13,020		)		896
Unrealized gain on trading securities		(9		)		—
Net purchases of trading securities		(15,797		)		—
Other		(118		)		—
Changes in operating assets and liabilities, net of working capital acquired:
Receivables		(25,332		)		53,691
Inventories		(1,566		)		(6,824		)
Other current assets		(11,020		)		(4,924		)
Accounts payable and accrued liabilities		13,478				(20,448		)
Other long-term liabilities		186				86
Net cash provided by operating activities		32,364				86,594
Cash flows from investing activities:
Additional acquisition costs		(46		)		(6,582		)
Investment in Starfish		—				(15,872		)
Capital expenditures		(140,711		)		(25,685		)
Proceeds from sale of property, plant and equipment		30				499
Net cash flows used in investing activities		(140,727		)		(47,640		)
Cash flows from financing activities:
Proceeds from long-term debt		189,500				56,800
Payments of long-term debt		(187,500		)		(74,212		)
Payments for debt issuance costs deferred financing costs and registration costs		(462		)		(459		)
Proceeds from MarkWest Energy’s private placement, net		134,950				5,000
Collection of related party notes receivable		—				24
Exercise of stock options		114				230
Excess income tax benefits from share-based compensation		91				—
Payment of dividends		(7,435		)		(3,447		)
Distributions to MarkWest Energy unitholders		(29,830		)		(17,586		)
Net cash flows provided by (used in) financing activities		99,428				(33,650		)
Net increase (decrease) in cash		$	(8,935	)		$	5,304
Cash and cash equivalents at beginning of year		48,844				20,968
Cash and cash equivalents at end of period		$	39,909			$	26,272
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amount capitalized		$	31,577			$	19,823
Cash paid for income taxes		3,937				584
Supplemental schedule of non-cash investing and financing activities:
Change in accrual of construction projects in progress		(28,348		)		1,072
Property, plant equipment asset retirement obligation		144				64
Accrued financing costs		—				1,580

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

MARKWEST HYDROCARBON, INC.
Notes to Condensed Consolidated Financial Statements
(unaudited)

1. Organization

MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon” or the “Company”) is an energy company primarily focused on marketing natural gas liquids and increasing shareholder value by growing MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), a consolidated subsidiary and publicly traded master limited partnership. MarkWest Energy Partners is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil. The Company also markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, Texas, Oklahoma, Gulf Coast and other areas of the Southwest.

2. Basis of Presentation

The Company’s unaudited condensed consolidated financial statements include the accounts of all majority-owned or controlled subsidiaries. The consolidated financial statements include the accounts of MarkWest Energy Partners, L.P. and MarkWest Energy GP, L.L.C. The Company consolidates the Partnership because it acts as the general partner and the limited partners to not have substantive kick-out or participating rights. Equity investments in which the Company exercises significant influence but does not control, and are 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 Company 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 Company’s December 31, 2006, Annual Report on Form 10-K/A. Finally, consider that results for the three and six months ended June 30, 2007, are not necessarily indicative of results for the full year 2007, or any other future period.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period presentation.

3. Recent Accounting Pronouncements

In September 2006 the FASB issued SFAS 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. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the impact of adopting this Statement.

In February 2007 the FASB issued SFAS 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. The new Statement 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. Statement 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity (1) makes that choice in the first 120 days of that fiscal year, (2) has not yet issued financial statements, and (3) elects to apply the provisions of SFAS 157, Fair Value Measurements. The Company is currently evaluating the impact of adopting this Statement.

4. Marketable Securities

As of June 30, 2007, the Company held short-term equity investments classified as trading securities. Realized and unrealized gains and losses on trading securities are included in earnings. Dividend and interest income are recognized when earned.

Marketable securities classified as available-for-sale are stated at market based on the closing price of the securities at the balance sheet date. Accordingly, unrealized gains are reflected in other comprehensive income, net of applicable income taxes. For losses that are other than temporary, the cost basis of the securities is written down to fair value, and the amount of the write down is reflected in the statement of operations. The Company utilizes a first-in first-out cost basis to compute realized gains and losses. Realized gains and losses, dividends, interest income, and the amortization of discounts and premiums are reflected in the statement of operations. Purchases and sales of securities are recognized on a trade-date basis.

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

	Cost Basis			Unrealized Gains			Unrealized Losses			Fair Value
June 30, 2007
Equity securities:
Trading securities		$	15,797		$	9		$	—		$	15,806
Available-for-sale securities		5,942			3,228			—			9,170
		$	21,739		$	3,237		$	—		$	24,976

	Cost Basis			Unrealized Gains			Unrealized Losses			Fair Value
December 31, 2006
Equity securities:
Available-for-sale securities		$	5,942		$	1,771		$	—		$	7,713

For the six months ended June 30, 2007, the Company recognized net unrealized gains on available-for-sale securities of $0.9 million, net of the related tax expense of $0.6 million. These gains are shown as a component of other comprehensive income for 2007.

For the six months ended June 30, 2007, the Company recognized net unrealized gains on trading securities of less then $0.1 million, net of the related tax expense of less than $0.1 million. The gains are included in income for 2007.

5. Equity Investment

The Partnership applies the equity method of accounting for its non-operating membership interest in Starfish Pipeline Company, LLC, (“Starfish”). Upon the acquisition of Starfish, there were differences between the purchase price allocated to the investments and the underlying equity of the subsidiaries attributable to the Partnership’s interest. The Partnership is amortizing these differences based upon the hypothetical purchase price allocation to the assets and liabilities of the subsidiaries as if the Partnership was consolidating Starfish. The difference between the carrying amount of the Partnership’s equity method investment and the underlying equity attributable to the Partnership’s interest is being amortized over 17 years. Summarized financial information for 100% of Starfish is as follows (in thousands):

	Three months ended June 30,				Six months ended June 30,
	2007		2006		2007		2006
Revenues	$	8,558	$	7,483	$	17,070	$	12,579
Operating income	3,500		1,678		7,553		3,104
Net income	3,455		2,599		7,130		4,632

6. Property, Plant and Equipment

Property, plant and equipment consists of (in thousands):

	June 30, 2007				December 31, 2006
Gas gathering facilities		$	453,606			$	289,586
Gas processing plants		218,031				217,080
Fractionation and storage facilities		23,609				23,470
Natural gas pipelines		42,343				42,361
Crude oil pipelines		19,113				19,113
NGL transportation facilities		5,326				5,326
Furniture, office equipment and other		2,641				2,641
Land, building and other equipment		22,427				20,705
Construction in progress		46,851				42,324
		833,947				662,606
Less: Accumulated depreciation		(125,635		)		(108,271		)
Total property, plant and equipment		$	708,312			$	554,335

The Company capitalizes interest on major projects during construction. For the three and six months ended June 30, 2007, the Company capitalized interest, including deferred finance costs, of $1.1 million and $2.3 million, respectively. For the three and six months ended June 30, 2006, the Company capitalized interest, including deferred finance costs, of less than $0.1 million and $0.2 million, respectively.

7. Long-Term Debt

Debt is summarized below (in thousands):

	June 30, 2007			December 31, 2006
MarkWest Hydrocarbon Credit Facility
8.75% interest		$	—		$	—
Partnership Credit Facility
8.75% interest, due December 2010		32,000			30,000
Partnership Senior Notes
6.875% interest, due November 2014		225,000			225,000
8.5% interest, net of original issue discount of $2,970 and $3,135, respectively, due July 2016		272,030			271,865
Total long-term debt		$	529,030		$	526,865

MarkWest Hydrocarbon

On August 18, 2006, the Company entered into the second amended and restated credit agreement (“Company Credit Facility”) which provides a maximum lending limit of $55.0 million, increased from $25.0 million; and extends the term from one to three years. The Company Credit Facility includes a $40.0 million revolving facility and a $15.0 million Unit Acquisition Facility. The $15.0 million unit acquisition facility may be used to finance the acquisition of MarkWest Energy Partners common or subordinated units.

On February 16, 2007, the Company entered into the first amendment to the second amended and restated Company Credit Facility, increasing the term by one year to August 20, 2010, and providing an additional $50.0 million of credit to enable the Company to meet potential margin requirements associated with its derivative instruments.

On March 15, 2007, the Company entered into the second amendment to the second amended and restated Company Credit Facility. This amendment clarifies language relating to the swap contracts between the Company and the lenders or lender’s affiliates in several sections of the Company Credit Facility. It provides that the non-borrowing base credit extension, as defined in the agreement, shall be used solely for the purpose of enabling the Company to meet margin requirements under swap contracts, as defined in the agreement, with counterparties that are not lenders or affiliates of the lenders.

The Company Credit Facility bears 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 Facility’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the revolver facility usage to the borrowing base, ranging from 0.50% to 1.75% for base rate loans, and 1.50% to 2.75% for Eurodollar rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 0.375% to 0.5%.

Under the provisions of the Company Credit Facility, the Company is subject to a number of restrictions on its business, including its ability to grant liens on assets; make or own certain investments; enter into any swap contracts other than in the ordinary course of business; merge, consolidate or sell assets; incur indebtedness (other than subordinated indebtedness); make distributions on equity investments; declare or make, directly or indirectly, any restricted distributions.

The Company Credit Facility also contains covenants requiring the Company to maintain:

· a leverage ratio (as defined in the credit agreement) of not greater than 4.0:1.0, or up to 5.5:1.0, in certain circumstances;

· a minimum net worth of a) $30.0 million plus, b) 50% of consolidated net income (if positive) earned on or after July 1, 2006, plus, c) 100% of net proceeds of all equity issued by the Company subsequent to August 18, 2006; and

· a minimum collateral coverage ratio of not less than 2.0: 1.0 as of the date of any determination.

MarkWest Energy Partners

Credit Facility

The Partnership’s wholly owned subsidiary, MarkWest Energy Operating Company, L.L.C., has a $250 million dollar revolving credit facility (the “Credit Facility”). The Credit Facility is guaranteed by the Partnership and substantially all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the Credit Facility bear interest at a variable interest rate, plus basis points. The basis points vary based on the ratio of the Partnership’s consolidated debt to consolidated EBITDA, as defined in the Fifth Amendment to the Credit Facility. For the six months ended June 30, 2007, the weighted average interest rate on the Credit Facility was 7.58%.

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants as defined in the fifth amendment to the Credit Facility. These covenants are used to calculate the available borrowing capacity on a quarterly basis, at June 30, 2007, available borrowings under the Credit Facility were $216.4 million.

Senior Notes

At June 30, 2007, the Partnership and its wholly owned subsidiary, MarkWest Energy Finance Corporation, had two series of senior notes outstanding: $225.0 million at a fixed rate of 6.875% due in November 2014 (the “2014 Notes”) and $272.0 million, net of unamortized discount of $3.0 million, at a fixed rate of 8.5% due in July 2016 (the “2016 Notes”), together (the “Senior Notes”). The estimated fair value of the Senior Notes was approximately $485.9 million and $499.8 million at June 30, 2007 and December 31, 2006, respectively, based on quoted market prices.

The Partnership has no independent assets or operations, other than investments in subsidiaries and issuances of debt. Each of the Partnership’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed 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 its Credit Facility.

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 indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.

The Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2016 Senior Notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (January 6, 2007), and, as a consequence incurred penalty interest of 0.5% from January 7, 2007 until February 26, 2007, when the exchange offer was completed.

8. Derivative Financial Instruments

Commodity Instruments

The Company’s primary risk management objective is to manage volatility in its cash flows. The Company has a committee comprised of the senior management team that oversees all of the risk management activity and continually monitors the Company’s risk management program and expects to continue to adjust its financial positions as conditions warrant. The Company uses mark-to-market accounting for its non-trading commodity derivative instruments, accordingly, the volatility in any given period related to unrealized gains or losses can be significant to the overall financial results of the Company; however, management ultimately expects those gains and losses to be offset when they become realized. The Company does not have any trading derivative financial instruments.

The Company utilizes a combination of fixed-price forward contracts, fixed-for-floating price swaps and options on the over-the-counter (“OTC”) market. The Company may also enter into futures contracts traded on the New York Mercantile Exchange (“NYMEX”). Swaps and futures contracts allow the Company to manage volatility in its margins because corresponding losses or gains on the financial instruments are generally offset by gains or losses in its physical positions.

The Company enters into OTC swaps with financial institutions and other energy company counterparties. The Company conducts a standard credit review on counterparties and has agreements containing collateral requirements where deemed necessary. The Company uses standardized swap agreements that allow for offset of positive and negative exposures. The Company may be subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.

Because of the strong correlation between NGL prices and crude oil prices and limited liquidity in the NGL financial market, the Company uses crude oil derivative instruments to manage NGL price risk. As a result of these transactions, the Company has mitigated its expected commodity price risk with agreements expiring at various times through the third quarter of 2010. The margins the Company earns from condensate sales are directly correlated with crude oil prices.

The use of derivative instruments may expose the Company 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) the Partnership’s 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 Company enters into derivative instruments, it may be prevented from realizing the benefits of favorable price changes in the physical market. The Company is similarly insulated, however, against unfavorable changes in such prices.

The Company may enter into physical and/or financial positions to manage its risks related to commodity price exposure for its Standalone segment. 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 Company may choose direct exposure when it is favorable as compared to the frac spread risk.

The Partnership’s primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude oil. Swaps and futures contracts may allow the Partnership to reduce 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 of physical product. While the Partnership largely expects its realized derivative gains and losses to be offset by increases or decreases in the value of its physical sales, the Partnership will experience volatility in reported earnings due to the recording of unrealized gains and losses on its derivative positions that will have no offset.

Fair value is based on available market information for the particular derivative instrument, and incorporates the commodity, period, volume and pricing. Where published market values are not readily available, the Company uses a third party service. Due to the use of mark-to market accounting, the fair value of our commodity derivative instruments is equal to the carrying value. The impact of the Company’s commodity derivative instruments on consolidated financial position are summarized below (in thousands):

	June 30, 2007				December 31, 2006
Fair value of derivative instruments:
Current asset		$	3,523			$	9,938
Noncurrent asset		4,496				2,794
Current liability		(18,624		)		(7,476		)
Noncurrent liability		(22,213		)		(1,460		)

Risk management deposits:
Current asset		702				1,009
Noncurrent asset		717				717

At June 30, 2007, and December 31, 2006, the Partnership recorded premium payments relating to certain put option contracts as risk management deposits. The premiums allowed the Partnership to secure specific pricing on those contracts. The payment is recorded as an asset and will be amortized through revenue as the puts expire or are exercised. The current and non-current risk management deposits have been recorded as “Other assets” and “Other long-term assets”, respectively, in the accompanying Condensed Consolidated Balance Sheets.

The Company accounts for the impact of its commodity derivative instruments as either a component of revenue or purchased product costs. Sales are recognized as a component of revenue and purchases as a component of purchased product costs. The Company also has a contract which creates a floor on the frac spread which can be realized on a specific volume purchased. Gains and losses from this contract are recorded as a component of purchased product costs. The Partnership accounts for the impact of its commodity derivative instruments as a component of revenue. The Partnership also has a contract allowing it to fix a component of the price of electricity at one of its plant locations. Unrealized gains (losses) from the contract are recognized as a component of facility expenses. The consolidated impact of the Company’s commodity derivative instruments on revenues are summarized below (in thousands):

	Three months ended June 30,								Six months ended June 30.
	2007				2006				2007				2006
Revenue:
Realized gain (loss)		$	(574	)		$	(476	)		$	4,687			$	63
Unrealized loss		(13,339		)		(12,581		)		(32,509		)		(14,379		)
Derivative loss		$	(13,913	)		$	(13,057	)		$	(27,822	)		$	(14,316	)

The consolidated impact of the Company’s commodity derivative instruments on purchased product costs and facility expenses are summarized below (in thousands):

	Three months ended June 30,							Six months ended June 30.
	2007				2006			2007				2006
Purchased product costs:
Realized loss		$	(799	)		$	—		$	(1,201	)		$	—
Unrealized loss		(5,538		)		—			(3,509		)		—
Facility expenses:
Unrealized loss		$	(1,029	)		$	—		$	(596	)		$	—

9. Income Taxes

The Company accounts for income taxes under the asset and liability method pursuant to 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 Company bases the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate. Income tax benefit totaled $2.9 million and $2.4 million for the three and six months ended June 30, 2007, respectively, resulting in an effective tax rate of 28.3%. Income tax expense totaled less than $0.1 million and $0.5 million for the comparable periods in 2006, resulting in an effective tax rate of 39.9%. The 2007 estimated annual effective income tax rate varies from the statutory rate mostly due to a change in the valuation allowance in the state net operating losses (“NOL”) related to the state NOL utilization.

The Company adopted FIN 48, effective January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. Specifically, the pronouncement prescribes a “more likely than not” recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. As a result of the implementation of FIN 48, the Company recognized a liability of $0.4 million for unrecognized income tax benefits, none of which would affect the Company’s effective tax rate if recognized. Included in the unrecognized income tax benefit is a $0.1 million reduction of retained earnings. Additionally, the Company anticipates approximately $0.3 million to reverse by December 31, 2007, as the Company is filing a change in method of accounting with the Internal Revenue Service.

The Company recognizes interest and penalties related to uncertain tax positions in interest and selling, general and administrative expense. As of the date of adoption, the Company has approximately $0.1 million of accrued interest and penalties related to uncertain tax positions.

The tax years 2002 through 2006 remain open to examination by the major taxing jurisdictions to which the Company is subject.

10. Stock and Incentive Compensation Plans

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

	Three months ended June 30,							Six months ended June 30.
	2007			2006				2007			2006
MarkWest Hydrocarbon
Stock options		$	—		$	13			$	—		$	35
Restricted stock		175			77				373			176
General partner interests under Participation Plan		6,182			2,464				13,773			3,973
Subordinated units under Participation Plan		—			(16		)		—			(29		)
MarkWest Energy Partners
Restricted units		220			113				1,179			571
Total compensation cost		$	6,577		$	2,651			$	15,325		$	4,726

Compensation expense has been recorded as “Selling, general and administrative expense” in the accompanying Condensed Consolidated Statements of Operations.

The following summarizes the total compensation cost as of June 30, 2007, related to non-vested awards not yet recognized. The actual compensation cost recognized might differ for the restricted units, as they qualify as liability awards, which are affected by changes in the fair value.

	Amount			Weighted- average Remaining Vesting Period
	(in thousands)			(years)
Restricted stock		$	1,086		2.1
Restricted units		2,500			1.9
Total		$	3,586

Stock Options

The following summarizes the impact of the Company’s stock option plans (in thousands of shares):

	Three months ended June 30,				Six months ended June 30.
	2007		2006		2007		2006
Options exercised, cashless		—		—		—		7
Shares issued, cashless		—		—		—		4
Options exercised, cash		13		23		14		30
Shares issued, cash		13		23		14		30

For the six months ended June 30, 2007 and 2006, the Company received $0.1 million and less than $0.1 million, respectively, for the exercise of stock options. The Company has not granted any stock options since 2004. The fair value of each option granted in 2004 was estimated using the Black-Scholes option-pricing model. The following assumptions were used to compute the weighted average fair value of options granted:

	2004
Expected life of options	6 years
Risk free interest rate	3.62	%
Estimated volatility	32	%
Dividend yield	4.7	%

As of June 30, 2007 the Company had not granted any stock options and there were no forfeitures or cancellations of exercisable options. A summary of the status of the Company’s stock options is presented below:

	Number of Shares			Weighted- average Exercise Price			Weighted- average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding and Exercisable at December 31, 2006		65,635			$	7.48
Exercised		(13,362	)		8.59
Outstanding and Exercisable at June 30, 2007		52,273			7.19			4.6	$	2,625,943

	Three months ended June 30,						Six months ended June 30.
	2007			2006			2007			2006
Total fair value of options vested during the period		$	—		$	44,834		$	—		$	67,186
Total intrinsic value of options exercised during the period		687,105			346,744			722,530			559,371

Restricted Stock

The following summarizes the impact of the Company’s restricted stock activity:

	Number of Shares			Weighted-average Grant-date Fair Value
Unvested at December 31, 2006		41,694			$	26.89
Granted		17,161			47.89
Vested		(7,197	)		20.51
Forfeited		(4,841	)		30.36
Unvested at June 30, 2007		46,817			35.21

	Six months ended June 30.
	2007			2006
Weighted-average grant-date fair value of restricted stock granted during the period		$	821,840		$	375,500
Total fair value of restricted stock vested during the period and total intrinsic value of restricted stock settled during the period		147,605			44,526

During the quarters ended June 30, 2007 and 2006, the Company received no proceeds for issuing restricted stock, and there were no cash settlements during the same periods.

MarkWest Energy Partners, L.P. Long-Term Incentive Plan

The following is a summary of restricted unit activity issued under the Partnership’s Long-Term Incentive Plan:

	Number of Units			Weighted-average Grant-date Fair Value
Non-vested at December 31, 2006		125,200			$	24.14
Granted		47,216			31.47
Vested		(40,376	)		23.52
Forfeited		(12,354	)		25.48
Non-vested at June 30, 2007		119,686			27.11

	Six months ended June 30.
	2007		2006
Weighted-average grant-date fair value of restricted units granted during the quarter	$	1,486,074	$	1,412,933
Total fair value of restricted units vested and total intrinsic value of restricted units settled during the quarter	1,261,750		447,841

During the quarters ended June 30, 2007 and 2006, the Partnership received no proceeds (other than the contributions by the general partner to maintain its 2% ownership interest) for issuing restricted units, and there were no cash settlements. Of the total number of restricted units that vested in the first quarter of 2007 and 2006, the Partnership did not redeem any restricted units for cash. For the six months June 30, 2007 and 2006, the Partnership issued 40,376 and 19,286 common units, respectively.

11. Dividends Paid to Shareholders

Cash Dividends

On July 20, 2007, the Company’s Board of Directors declared a quarterly cash dividend of $0.36 per share, payable on August 21, 2007, to the stockholders of record as of the close of business on August 9, 2007. The ex-dividend date will be August 7, 2007.

On April 20, 2007, the Company’s Board of Directors declared a quarterly cash dividend of $0.32 per share, was paid on May 22, 2007, to the stockholders of record as of the close of business on May 10, 2007. The ex-dividend date was May 8, 2007.

On January 26, 2007, the Company’s Board of Directors declared a quarterly cash dividend of $0.30 per share, was paid on February 21, 2007, to the stockholders of record as of the close of business on February 9, 2007. The ex-dividend date was February 7, 2007.

12. Earnings Per Share

Basic and diluted income (loss) per common share are computed in accordance with SFAS No. 128, Earnings per Share. Basic income (loss) per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding. For the three months ended June 30, 2007 and 2006, there is no difference between basic and diluted income (loss) per share since potential common shares from the exercises of stock options are anti-dilutive and are, therefore, excluded from the calculation of income (loss) per share.

The following are the number of shares used to compute the basic and diluted (loss) earnings per share (in thousands, except per share data):

	Three months ended June 30,								Six months ended June 30,
	2007				2006				2007				2006
Net (loss) income		$	(7,272	)		$	(2,132	)		$	(6,315	)		$	700
Weighted average common shares outstanding during the period		11,996				11,936				11,991				11,921
Effect of dilutive instruments(1)		—				—				—				125
Weighted average common shares outstanding during the period including the effects of dilutive instruments(1)		11,996				11,936				11,991				12,046
Net (loss) income per share:
Basic		$	(0.61	)		$	(0.18	)		$	(0.53	)		$	0.06
Diluted(1)		$	(0.61	)		$	(0.18	)		$	(0.53	)		$	0.06

(1) Due to the Company’s net loss for the three months ended June 30, 2007 and 2006, and six months ended June 30, 2007, 57,843, 114,452 and 57,665 shares, respectively, were excluded from the calculation of diluted shares because the common shares were anti-dilutive.

13. Commitments and Contingencies

The Company 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 Company maintains insurance policies in amounts and with coverage and deductibles as it believes are reasonable and prudent. However, the Company cannot assure either that the insurance companies will promptly honor its policy obligations or that the coverage or levels of insurance will be adequate to protect it from all material expenses related to future claims for property loss or business interruption to the Company or the Partnership (collectively 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 the ALPS Pipeline, a natural gas liquids (NGL) pipeline owned by Equitable Production Company and leased and operated by the Partnership’s 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 responds 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, the Company and the Partnership have filed an action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed

to the U.S. District Court for the District of Colorado, (Civil Action No. 1:05-CV-1948, on October 7, 2005) against their All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain costs related to the pipeline incident. These costs include MarkWest’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred for transporting the liquids while the pipeline was out of service; reduced volumes of liquids that could be processed; and 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. Neither the Company nor the Partnership have provided for a receivable for any of the claims in this action because of the uncertainty as to whether and how much they will ultimately recover under the policies. The costs associated with this claim have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if and when it is received. The Defendant insurance companies and MarkWest have each filed separate summary judgment motions in the action and these motions are pending with the Court. Discovery in the action is also continuing.

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, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28TH Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), 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 Gonzales action was settled in early 2006, pursuant to a mediation held December 9, 2005. The other 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.

In February 2007 the Company learned that a default judgment had been entered against it in May 2006, in an action entitled Runyan v. Eclipse Realty LLC et al, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and complaint and was not given any notification of a motion for default judgment. The action involved a personal injury claim by an individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. On April 4, 2007, the Court granted the Company’s motion to set aside the default judgment and also granted the Company’s motion to dismiss MarkWest from the action entirely.

In the ordinary course of business, the Company and the Partnership are 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 Company’s financial condition, liquidity or results of operations.

14. Segment Reporting

MarkWest Hydrocarbon’s operations are classified into two reportable segments:

1. MarkWest Hydrocarbon Standalone—The Company sells its equity and third-party NGLs, purchases third-party natural gas and sells its equity and third-party natural gas. Between February 2004 and June 2006, when the agreement was terminated, the Company was engaged in the wholesale propane marketing business through a third party agency agreement. MarkWest Hydrocarbon Standalone operates MarkWest Energy Partners, a publicly traded limited partnership.

2. MarkWest Energy Partners—The Partnership is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.

The Company evaluates the performance of its segments and allocates resources to them based on operating income. The Company conducts its operations in the United States of America.

Net income or net loss for each segment includes total revenues minus purchased product costs, facility expenses, selling, general and administrative expenses, depreciation, amortization of intangible assets, accretion of asset retirement obligations and impairments and excludes interest income, interest expense, amortization of deferred financing costs, gain on sale of non-operating assets, non-controlling interest in net income of consolidated subsidiary, miscellaneous income or expense and income taxes.

Selling, general and administrative expenses are allocated to the segments based on direct expenses incurred by the segments or allocated based on the percent of time that employees devote to the segment in accordance with the Partnership’s services agreement with the Company. The tables below present information about the net income for the reported segments for the three and six months ended June 30, 2007 and 2006.

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

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Consolidating Entries				Total
Revenue:
Revenue		$	52,159		$	144,026			$	(19,292	)	$	176,893
Derivative loss		(6,550		)	(7,363		)		—			(13,913		)
Total revenue		45,609			136,663				(19,292		)	162,980
Purchased product costs		48,706			74,213				(13,412		)	109,507
Facility expenses		4,206			20,303				(6,094		)	18,415
Selling, general and administrative expenses		6,345			12,475				—			18,820
Depreciation		198			9,127				—			9,325
Amortization of intangible assets		—			4,168				—			4,168
Accretion of asset retirement and lease obligations		—			28				—			28
(Loss) income from operations		(13,846		)	16,349				214			2,717
Other income (expense):
Earnings from unconsolidated affiliates		—			1,656				—			1,656
Interest income		645			479				—			1,124
Interest expense		(63		)	(8,991		)		—			(9,054		)
Amortization of deferred financing costs (a component of interest expense)		(70		)	(661		)		—			(731		)
Dividend income		136			81				—			217
Miscellaneous expense		(2		)	(532		)		—			(534		)
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(13,200		)	8,381				214			(4,605		)
Non-controlling interest in net income of consolidated subsidiary		—			—				(5,562		)	(5,562		)
Interest in net income of consolidated subsidiary		2,800			—				(2,800		)	—
(Loss) income before income taxes		(10,400		)	8,381				(8,148		)	(10,167		)
Provision for income tax (expense) benefit		2,914			(106		)		87			2,895
Net (loss) income		$	(7,486	)	$	8,275			$	(8,061	)	$	(7,272	)

Three months ended June 30, 2006 (in thousands):

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Consolidating Entries				Total
Revenue:
Revenue		$	62,189		$	142,041			$	(17,879	)	$	186,351
Derivative loss		(6,156		)	(6,901		)		—			(13,057		)
Total revenue		56,033			135,140				(17,879		)	173,294
Purchased product costs		52,205			76,244				(11,926		)	116,523
Facility expenses		5,106			15,160				(5,953		)	14,313
Selling, general and administrative expenses		4,073			8,988				—			13,061
Depreciation		394			7,384				—			7,778
Amortization of intangible assets		—			4,027				—			4,027
Accretion of asset retirement and lease obligations		—			26				—			26
(Loss) income from operations		(5,745		)	23,311				—			17,566

Other income (expense):
Earnings from unconsolidated affiliates		—			1,228				—			1,228
Interest income		177			259				—			436
Interest expense		(84		)	(10,714		)		—			(10,798		)
Amortization of deferred financing costs (a component of interest expense)		(33		)	(826		)		—			(859		)
Dividend income		109			—				—			109
Miscellaneous income		2			1,515				—			1,517
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(5,574		)	14,773				—			9,199
Non-controlling interest in net income of consolidated subsidiary		—			—				(11,273		)	(11,273		)
Interest in net income of consolidated subsidiary		3,364			—				(3,364		)	—
(Loss) income before income taxes		(2,210		)	14,773				(14,637		)	(2,074		)
Provision for income tax benefit (expense)		78			(679		)		543			(58		)
Net (loss) income		$	(2,132	)	$	14,094			$	(14,094	)	$	(2,132	)

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

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Consolidating Entries				Total
Revenue:
Revenue		$	125,085		$	265,572			$	(38,367	)	$	352,290
Derivative loss		(13,530		)	(14,292		)		—			(27,822		)
Total revenue		111,555			251,280				(38,367		)	324,468
Purchased product costs		101,520			138,218				(26,024		)	213,714
Facility expenses		9,775			33,259				(12,557		)	30,477
Selling, general and administrative expenses		13,218			26,317				—			39,535
Depreciation		586			16,913				—			17,499
Amortization of intangible assets		—			8,336				—			8,336
Accretion of asset retirement and lease obligations		—			55				—			55
(Loss) income from operations		(13,544		)	28,182				214			14,852
Other income (expense):
Earnings from unconsolidated affiliates		—			3,423				—			3,423
Interest income		1,121			2,399				—			3,520
Interest expense		(122		)	(18,346		)		—			(18,468		)
Amortization of deferred financing costs (a component of interest expense)		(129		)	(1,322		)		—			(1,451		)
Dividend income		258			81				—			339
Miscellaneous expense		(145		)	(1,261		)		—			(1,406		)
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(12,561		)	13,156				214			809
Non-controlling interest in net income of consolidated subsidiary		—			—				(9,522		)	(9,522		)
Interest in net income of consolidated subsidiary		3,612			—				(3,612		)	—
(Loss) income before income taxes		(8,949		)	13,156				(12,920		)	(8,713		)
Provision for income tax benefit (expense)		2,420			(125		)		103			2,398
Net (loss) income		$	(6,529	)	$	13,031			$	(12,817	)	$	(6,315	)

Six months ended June 30, 2006 (in thousands):

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Consolidating Entries				Total
Revenue:
Revenue		$	164,281		$	298,783			$	(35,594	)	$	427,470
Derivative loss		(7,655		)	(6,661		)		—			(14,316		)
Total revenue		156,626			292,122				(35,594		)	413,154
Purchased product costs		144,527			177,205				(23,581		)	298,151
Facility expenses		10,579			29,229				(12,013		)	27,795
Selling, general and administrative expenses		7,111			17,326				—			24,437
Depreciation		599			14,557				—			15,156
Amortization of intangible assets		—			8,043				—			8,043
Accretion of asset retirement and lease obligations		—			51				—			51
(Loss) income from operations		(6,190		)	45,711				—			39,521
Other income (expense):
Earnings from unconsolidated affiliates		—			2,173				—			2,173
Interest income		363			479				—			842
Interest expense		(152		)	(21,690		)		—			(21,842		)
Amortization of deferred financing costs (a component of interest expense)		(50		)	(1,634		)		—			(1,684		)
Dividend income		215			—				—			215
Miscellaneous income		152			3,607				—			3,759
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(5,662		)	28,646				—			22,984
Non-controlling interest in net income of consolidated subsidiary		—			—				(21,817		)	(21,817		)
Interest in net income of consolidated subsidiary		6,693			—				(6,693		)	—
(Loss) income before income taxes		1,031			28,646				(28,510		)	1,167
Provision for income tax expense		(331		)	(679		)		543			(467		)
Net income		$	700		$	27,967			$	(27,967	)	$	700

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

Forward-Looking Statements

Statements included in this quarterly report on Form 10-Q that are not historical facts are forward-looking statements. We use words such as “may,” “believe,” “estimate,” “expect,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

Management bases these statements on its expectations, estimates, assumptions and beliefs concerning future events affecting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied.

Forward-looking statements relate to, among other things:

· our expectations regarding MarkWest Energy Partners, L.P.;

· our ability to grow MarkWest Energy Partners, L.P.;

· our expectations regarding natural gas and NGL products and prices;

· our efforts to increase fee-based contract volumes;

· our ability to manage our commodity price risk;

· our ability to maximize the value of our NGL output;

· the adequacy of our general public liability, property, and business interruption insurance; and

· our ability to comply with environmental and governmental regulations.

Important factors that could cause our actual results of operations or actual financial condition to differ include, but are not necessarily limited to:

· the availability of raw natural gas supply for our gathering and processing services;

· the availability of NGLs for our transportation, fractionation and storage services;

· prices of NGL products, crude oil and natural gas, including the effectiveness of any hedging activities;

· our ability to negotiate favorable marketing agreements;

· the risk that third-party natural gas exploration and production activities will not occur or be successful;

· competition from other NGL processors, including major energy companies;

· our dependence on certain significant customers, producers, gatherers, treaters and transporters of natural gas;

· our dependence on the earnings and distributions of the Partnership;

· the Partnership’s ability to successfully integrate its recent and future acquisitions;

· the Partnership’s ability to identify and complete organic growth projects or acquisitions complementary to its business;

· the Partnership’s substantial debt and other financial obligations could adversely affect its financial condition;

· the Partnership’s ability to raise sufficient capital to execute our business plan through borrowing or issuing equity;

· changes in general economic conditions in regions where our products are located;

· the success of our risk management policies;

· the operational hazards and availability and cost of insurance on our assets and operations;

· the damage to facilities and interruption of service due to casualty, weather, mechanical failure or any extended or extraordinary maintenance or inspection that may be required;

· the impact of any failure of our information technology systems;

· the impact of current and future laws and government regulations;

· the liability for environmental claims;

· the impact of the departure of any key personnel or executive officers;

· weather conditions; and

· the threat of terrorist attacks or war.

This list is not necessarily complete. Other unknown or unpredictable factors could also have material adverse effects on future results. The Company does not update publicly any forward-looking statement with new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements as many of these factors are beyond our ability to control or predict. Additional information concerning these and other factors is contained in our SEC filings, including but not limited to, our Annual Report on Form 10-K/A for the year ended December 31, 2006.

Overview

We were founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering of common shares in 1996. We are an energy company primarily focused on marketing natural gas liquids in support of our Appalachian processing agreements and increasing shareholder value by growing MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), our consolidated subsidiary and a publicly traded master limited partnership. The Partnership is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.

MarkWest Hydrocarbon’s assets consist primarily of partnership interests in the Partnership and certain processing agreements in Appalachia. As of June 30, 2007, the Company owned a 15% interest in the Partnership, consisting of the following:

· 3,738,992 common units and 1,200,000 subordinated units, representing a 13% limited partner interest in the Partnership; and

· An 89.7% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which in turn owns a 2% general partner interest and all of the incentive distribution rights in the Partnership.

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

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

· The nature of the business from which we derive our revenues and from which the Partnership derives its revenues;

· The nature of our relationship with MarkWest Energy Partners; and

· MarkWest Energy Partners’ acquisition activity.

Net Operating Margin (a non-GAAP financial measure)

Management evaluates performance on the basis of net operating margin (a “non-GAAP” financial measure), which is defined as income (loss) from operations, excluding facility cost, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement. 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 accounting principles generally accepted in the United States of America (“GAAP”). Our usage of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

The following reconciles this non-GAAP financial measure to the most comparable GAAP financial measure for the three and six months ended June 30, 2007 and 2006 (in thousands):

	Three months ended June 30,				Six months ended June 30.
	2007		2006		2007		2006
Revenue	$	162,980	$	173,294	$	324,468	$	413,154
Purchased product costs	109,507		116,523		213,714		298,151
Net operating margin	53,473		56,771		110,754		115,003
Facility expenses	18,415		14,313		30,477		27,795
Selling, general and administrative expenses	18,820		13,061		39,535		24,437
Depreciation	9,325		7,778		17,499		15,156
Amortization of intangible assets	4,168		4,027		8,336		8,043
Accretion of asset retirement obligations	28		26		55		51
Income from operations	$	2,717	$	17,566	$	14,852	$	39,521

Our Business

MarkWest Hydrocarbon Standalone

Our marketing group markets NGL production in Appalachia. In the second quarter of 2007, we sold approximately 28.2 million gallons of NGLs extracted at the Partnership’s Siloam facility. This includes approximately 10.6 million gallons sold on behalf of the Partnership at no mark-up in the standalone segment. We ship NGL products from Siloam by truck, rail and barge. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best-efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations also purchase natural gas for delivery to the account of producers, pursuant to our keep-whole processing contracts.

We strive to maximize the value of our NGL output by marketing directly to our customers. We minimize the use of third-party brokers, preferring instead to support a direct marketing staff focused on multi-state and independent dealers. Additionally, we use our own trailer and railcar fleet, our own terminal, and owned and leased storage facilities, all of which serve to enhance supply reliability to our customers. These efforts have allowed us to generally maintain premium pricing for the majority of our NGL products.

In Appalachia, we have entered into various operating agreements with one customer related to the delivery of natural gas into its transmission facilities, located upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, the customer has agreed to use reasonable, diligent efforts to supply these facilities with consistent volumes of natural gas it ships on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through February 9, 2015, with annual renewals thereafter.

Consistent with the Partnership’s operating agreements with this same customer, the Partnership enters into contracts with natural gas producers for production to occur in the Partnership’s Kenova, Boldman and Cobb facilities, before delivery of the producer’s natural gas to the customer’s transmission facilities. We have contractual commitments with over 250 such producers in Appalachia. Under the provisions of our contracts with the Appalachian producers, the producers have committed all of the natural gas they deliver into the customer’s transmission facilities upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities for processing.

As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to the Partnership as discussed below), we earn a fee and also retain the NGLs produced under keep-whole agreements. In return, we are required to replace, in dry natural gas, the Btu content of the NGLs extracted.

In September 2004 we entered into several new and amended agreements with one of the largest producers in the Appalachia region. These agreements, which expire in 2009, with the option to extend until 2015, reduce our exposure to commodity price risk, for approximately 25% of our keep-whole gas volumes.

Our natural gas marketing group markets natural gas for the Partnership, purchases the necessary replacement Btu gas requirements and assists with business development efforts. From February 2004 through June 2006, the Company engaged in the wholesale propane marketing business through a third party agency agreement. The Company completed the terms of the termination agreement with the third party agency in February 2007. MarkWest Hydrocarbon also enters into future sale agreements that, as derivative instruments, are marked-to-market.

MarkWest Energy Partners

The Partnership generates the majority of its revenue and net operating margin from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage; and crude oil gathering and transportation. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described below. While all of these services constitute midstream energy operations, the Partnership provides services under the following different types of arrangements:

· Fee-based arrangements. The Partnership receives 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 the Partnership earns 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, these arrangements provide for minimum annual payments. If a sustained decline in

commodity prices were to result in a decline in volumes, the Partnership’s revenues from these arrangements would be reduced.

· Percent-of-proceeds arrangements. The Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices, and remits to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer, and sells the volumes it keeps to third parties at market prices. Generally, under these types of arrangements its revenues and net operating margins increase as natural gas, condensate and NGL prices increase, and its revenues and net operating margins decrease as natural gas and NGL prices decrease.

· Percent-of-index arrangements. The Partnership generally purchases 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. It then gathers and delivers the natural gas to pipelines, where it resells the natural gas at the index price, or at a different percentage discount to the index price. The net operating margins the Partnership realizes under these arrangements decrease in periods of low natural gas prices, because these net operating margins are based on a percentage of the index price. Conversely, the Partnership’s net operating margins increase during periods of high natural gas prices.

· Keep-whole arrangements. The Partnership gathers natural gas from the producer, processes the natural gas, and sells 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, the Partnership 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 the Partnership’s revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decreases as the price of natural gas increases relative to the price of condensate and NGLs.

· Settlement margin. Typically, the Partnership is allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses. To the extent the gathering system is operated more efficiently than specified per contract allowance, the Partnership is entitled to retain the difference for its own account.

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

As of June 30, 2007, the Partnership’s primary exposure to keep-whole contracts was limited to its Arapaho (Oklahoma) processing plant and its East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specification; however, the Partnership has the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately 25% (as measured in volumes) of the related gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low-processing margin environment.

Approximately 13% of the gas processed in East Texas for producers was processed under keep-whole terms. The Partnership’s keep-whole exposure in this area was offset to a great extent because the East Texas agreements provide for the retention of natural gas as a part of the gathering and compression arrangements with all producers on the system. This excess gas helps offset the amount of replacement natural gas purchases required to keep its producers whole on an MMBtu basis, thereby creating a partial

natural hedge. The net result is a significant reduction in volatility for these changes in natural gas prices. The remaining volatility for these contracts results from changes in NGL prices. The Partnership has an active commodity risk management program in place to reduce the impacts of changing NGL prices.

For the six months ended June 30, 2007, we calculated the following approximate percentages of the Partnership’s revenue and net operating margin from the following types of contracts:

	Fee-Based			Percent-of-Proceeds(1)			Percent-of-Index(2)			Keep-Whole(3)
Revenue		20	%		26	%		35	%		19	%
Net operating margin		38	%		35	%		12	%		15	%

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

(2) Includes settlement margin, condensate sales 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.

The Partnership’s short natural gas positions under keep-whole contracts are largely offset by its long positions in other operating areas. As a result, the net exposure to natural gas is not significant. While the percentages in the table above accurately reflect the percentages by contract type, the Partnership manages its business by taking into account the offset described above, required levels of operational flexibility and the fact that its 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 60%, 0% and 2%, respectively.

Our Relationship with MarkWest Energy Partners

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services in Appalachia to us for a fee. Additionally, MarkWest Energy Partners receives 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with GAAP, MarkWest Energy Partners’ financial results are included in our consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation.

As a result of the contracts mentioned above, the Company is one of the Partnership’s largest customers. For the six months ended June 30, 2007, we accounted for 14% of the Partnership’s revenues and 11% of its net operating margin, respectively, compared to 12% of revenues and 13% of net operating margin for the six months ending June 30, 2006.

We control and operate MarkWest Energy Partners through our majority ownership in the Partnership’s general partner. Our employees are responsible for conducting the Partnership’s business and operating its assets pursuant to a Services Agreement, which was formalized and made effective January 1, 2004.

A large portion of our cash flows consist of the distributions we receive from the Partnership based on our ownership interests. The Partnership is required by its partnership agreement to distribute available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash the Partnership can distribute on its units depends principally on the amount of cash generated from its operations.

Incentive distribution rights entitle the general partner to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us

to receive 13% of all cash distributed in a quarter after each unit has received $0.275 for that quarter; 23% of all cash distributed after each unit has received $0.3125 for that quarter; and 48% of all cash distributed after each unit has received $0.375 for that quarter.

Distributions by the Partnership have increased from $0.25 per unit for the quarter ended September 30, 2002 (its first full quarter of operation after its initial public offering), to $0.53 per unit for the quarter ended June 30, 2007. As a result, our distributions from the Partnership pursuant to our ownership of common and subordinated units have increased from $1.2 million for the quarter ended September 30, 2002 to $2.6 million for the quarter ended June 30, 2007; our distributions pursuant to our 2% general partner interest have increased from less than $0.1 million to approximately $0.5 million; and our distributions pursuant to our incentive distribution rights have increased from zero to $5.7 million. In total, our total distributions from our investment in the Partnership have increased from $1.3 million for the quarter ended September 30, 2002 to $8.8 million for the quarter ended June 30, 2007. As a result, we have increased our dividend from $0.02 per share for the quarter ended March 31, 2004 (our first dividend payout) to $0.36 per share for the quarter ended June 30, 2007.

Acquisitions by MarkWest Energy Partners

A significant part of the Partnership’s business strategy includes acquiring additional businesses that will allow it to increase distributions to its unitholders. The Partnership regularly considers and enters into discussions regarding potential acquisitions. These transactions may be effectuated quickly, may occur at any time and may be significant in size relative to the Partnership’s existing assets and operations.

Since the Partnership’s initial public offering, it has completed nine acquisitions for an aggregate purchase price of approximately $810 million. The following table contains information regarding each of these acquisitions (consideration in millions):

Name

Assets

Location

Consideration

Closing Date

Santa Fe

Grimes gathering system

Oklahoma

15.0

December 29, 2006

Javelina(1)

Gas processing and fractionation facility

Corpus Christi, Texas

398.8

November 1, 2005

Starfish(2)

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) Consideration includes $35.5 million in cash.

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

Results of Operations

MarkWest Hydrocarbon Standalone Results

For the three months ended June 30, 2007, MarkWest Hydrocarbon Standalone reported an operating loss of $13.8 million, compared to an operating loss of $5.7 million for the comparable quarter of 2006. MarkWest Hydrocarbon Standalone also reported a net loss of $7.5 million for the three months ended June 30, 2007, compared to a net loss of $2.1 million for the comparable quarter of 2006.

For the six months ended June 30, 2007, MarkWest Hydrocarbon Standalone reported an operating loss of $13.5 million, compared to an operating loss of $6.2 million for the comparable period of 2006. MarkWest Hydrocarbon Standalone also reported a net loss of $6.5 million for the six months ended June, 2007, compared to a net income of $0.7 million for the comparable quarter of 2006.

Cash Dividends

We declared a dividend of $0.36 per share on July 20, 2007 for the quarter ended June 30, 2007. The dividend declared is an increase of $0.04, or 13%, per share over the 2007 first quarter dividend and an increase of $0.12, or 50%, per share over the comparable period in 2006.

We declared a dividend of $0.32 per share on April 20, 2007 for the quarter ended March 31, 2007. The dividend declared was an increase of $0.02, or 7%, per share over the 2006 fourth quarter dividend and an increase of $0.16, or 101 %, per share over the comparable period in 2006.

MarkWest Energy Partners Results

For the three months ended June 30, 2007, the Partnership reported operating income of $16.3 million compared to $23.3 million for the corresponding quarter of 2006, a decrease of $7.0 million, or 30%. The Partnership also reported net income of $8.3 million in the second quarter of 2007, compared to $14.1 million in 2006.

For the six months ended June 30, 2007, the Partnership reported operating income of $28.2 million compared to $45.7 million for the corresponding quarter of 2006, a decrease of $17.5 million, or 38%. The Partnership also reported net income of $13.0 million in for the six month period in 2007, compared to $28.0 million in 2006.

Operating Data

	Three months ended June 30,		%			Six months ended June 30,		%
	2007	2006	Change			2007	2006	Change
MarkWest Hydrocarbon Standalone:
Marketing
Hydrocarbon frac spread sales (gallons)	17,605,000	19,027,000		(7.5	)%	68,681,000	58,511,000		17.4	%
Maytown sales (gallons)	10,639,000	10,468,000		1.6	%	22,047,000	20,951,000		5.2	%
Total NGL product sales (gallons)(1)	28,244,000	29,495,000		(4.2	)%	90,728,000	79,462,000		14.2	%
Wholesale
NGL product sales (gallons)(2)	N/A	7,867,000		N/A		N/A	35,063,000		N/A
MarkWest Energy Partners:
East Texas:
Gathering systems throughput (Mcf/d)	407,000	375,000		8.5	%	404,000	360,000		12.2	%
NGL product sales (gallons)	44,486,000	40,461,000		9.9	%	86,274,000	75,897,000		13.7	%
Oklahoma :
Foss Lake gathering system throughput (Mcf/d)	103,700	84,500		22.7	%	99,400	86,100		15.4	%
Woodford gathering system throughput (Mcf/d)(3)	102,800	N/A		N/A		76,900	N/A		N/A
Grimes gathering system throughput (Mcf/d)(4)	11,200	N/A		N/A		11,900	N/A		N/A
Arapaho NGL product sales (gallons)	22,233,000	19,615,000		13.3	%	42,758,000	38,032,000		12.4	%
Other Southwest:
Appleby gathering system throughput (Mcf/d)	58,000	33,600		72.6	%	53,400	33,600		58.9	%
Other gathering systems throughput (Mcf/d)	9,600	21,900		(56.2	)%	13,000	20,500		(36.6	)%
Lateral throughput volumes (Mcf/d)	68,100	93,600		(27.2	)%	59,200	71,500		(17.2	)%
Appalachia:
Natural gas processed (Mcf/d)	196,000	197,000		(0.5	)%	199,000	201,000		(1.0	)%
NGLs fractionated (Gal/d)	442,000	450,000		(1.8	)%	455,000	450,000		1.1	%
NGL product sales (gallons)	10,639,000	10,468,000		1.6	%	22,047,000	20,951,000		5.2	%
Michigan:
Natural gas throughput (Mcf/d)	6,100	5,800		5.2	%	6,100	5,200		17.3	%
NGL product sales (gallons)	1,065,000	1,394,000		(23.6	)%	2,190,000	2,843,000		(23.0	)%
Crude oil transported (Bbl/d)	14,200	14,900		(4.7	)%	14,200	14,600		(2.6	)%
Gulf Coast:
Refinery off-gas processed (Mcf/d)	102,000	130,000		(21.5	)%	115,000	125,000		(8.0	)%
Liquids fractionated (Bbl/d)	24,100	26,900		(10.4	)%	24,500	25,900		(5.4	)%

(1) Represents sales at the Siloam fractionator.

(2) Represents sales from our wholesale business. In December 2006, the Company terminated its wholesale agreement.

(3) The Partnership began constructing the Woodford gathering system in December 2006.

(4) The Partnership acquired the Grimes gathering system in December 2006.

Segment Reporting

Three months ended June 30, 2007, compared to the three months ended June 30, 2006

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Consolidating Entries				Total
Three months ended June 30, 2007:
Revenue:
Revenue		$	52,159		$	144,026			$	(19,292	)	$	176,893
Derivative loss		(6,550		)	(7,363		)		—			(13,913		)
Total revenue		45,609			136,663				(19,292		)	162,980
Purchased product costs		48,706			74,213				(13,412		)	109,507
Net operating margin		(3,097		)	62,450				(5,880		)	53,473
Operating expenses:
Facility expenses		4,206			20,303				(6,094		)	18,415
Selling, general and administrative expenses		6,345			12,475				—			18,820
Depreciation		198			9,127				—			9,325
Amortization of intangible assets		—			4,168				—			4,168
Accretion of asset retirement and lease obligations		—			28				—			28
(Loss) income from operations		(13,846		)	16,349				214			2,717
Other income (expense):
Earnings from unconsolidated affiliates		—			1,656				—			1,656
Interest income		645			479				—			1,124
Interest expense		(63		)	(8,991		)		—			(9,054		)
Amortization of deferred financing costs (a component of interest expense)		(70		)	(661		)		—			(731		)
Dividend income		136			81				—			217
Miscellaneous expense		(2		)	(532		)		—			(534		)
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(13,200		)	8,381				214			(4,605		)
Non-controlling interest in net income of consolidated subsidiary		—			—				(5,562		)	(5,562		)
Interest in net income of consolidated subsidiary		2,800			—				(2,800		)	—
(Loss) income before income taxes		(10,400		)	8,381				(8,148		)	(10,167		)
Provision for income tax benefit (expense)		2,914			(106		)		87			2,895
Net (loss) income		$	(7,486	)	$	8,275			$	(8,061	)	$	(7,272	)

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Consolidating Entries				Total
Three months ended June 30, 2006:
Revenue:
Revenue		$	62,189		$	142,041			$	(17,879	)	$	186,351
Derivative loss		(6,156		)	(6,901		)		—			(13,057		)
Total revenue		56,033			135,140				(17,879		)	173,294
Purchased product costs		52,205			76,244				(11,926		)	116,523
Net operating margin		3,828			58,896				(5,953		)	56,771
Operating expenses:
Facility expenses		5,106			15,160				(5,953		)	14,313
Selling, general and administrative expenses		4,073			8,988				—			13,061
Depreciation		394			7,384				—			7,778
Amortization of intangible assets		—			4,027				—			4,027
Accretion of asset retirement and lease obligations		—			26				—			26
(Loss) income from operations		(5,745		)	23,311				—			17,566
Other income (expense):
Earnings from unconsolidated affiliates		—			1,228				—			1,228
Interest income		177			259				—			436
Interest expense		(84		)	(10,714		)		—			(10,798		)
Amortization of deferred financing costs (a component of interest expense)		(33		)	(826		)		—			(859		)
Dividend income		109			—				—			109
Miscellaneous income		2			1,515				—			1,517
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(5,574		)	14,773				—			9,199
Non-controlling interest in net income of consolidated subsidiary		—			—				(11,273		)	(11,273		)
Interest in net income of consolidated subsidiary		3,364			—				(3,364		)	—
(Loss) income before income taxes		(2,210		)	14,773				(14,637		)	(2,074		)
Provision for income tax benefit (expense)		78			(679		)		543			(58		)
Net (loss) income		$	(2,132	)	$	14,094			$	(14,094	)	$	(2,132	)

MarkWest Hydrocarbon Standalone

Revenue. Revenue decreased $10.0 million, or 16%, for the three months ended June 30, 2007, compared to the corresponding period in 2006. The expiration of a wholesale marketing arrangement contributed $8.5 million to the decrease in revenues. In addition, we realized a $3.4 million decrease in our gas marketing revenues primarily due to lower volumes of 7,500 MMBtu/d, which were partially offset by an increase in price of $0.88 per MMBtu in 2007. These decreases were partially offset by an increase in our frac spread NGL revenues of $2.9 million resulting from increased prices of $0.19 per gallon, offset slightly by a decrease in 2007 volumes of 15,000 Gal/d.

Derivative (Loss) Gain. Losses from derivative instruments increased $0.4 million during the three months ended June 30, 2007 compared to the corresponding period in 2006. The mark-to-market adjustments resulted in a $0.2 million decrease in unrealized losses, which are non-cash items, and a $0.6 million increase in realized losses, when comparing the second quarter of 2007 to 2006 results.

Purchased Product Costs. Purchased product costs decreased $3.5 million, or 7%, for the three months ended June 30, 2007, compared to the corresponding period in 2006. The change was due to an $8.4 million decrease in purchased product costs in our wholesale business that is attributable to the expiration of a marketing arrangement and a $4.1 million decrease that resulted from price and volume decreases in our natural gas marketing business. These decreases were partially offset by an increase in our frac spread purchase product costs of $2.6 million, resulting primarily from decreased prices. Losses from derivative instruments increased $4.6 million. The increased loss was made up of an additional $3.8 million of unrealized loss and $0.8 million of realized loss. Finally, the value of a certain contract is marked-to-market based on an index price through purchased product costs, which resulted in an additional $1.7 million increase in unrealized losses.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $2.3 million, or 56%, during the three months ended June 30, 2007, compared to the corresponding period in 2006. This increase was primarily due to a $2.2 million non-cash increase to the participation plan compensation expense as a result of the Partnership’s increased market value.

MarkWest Energy Partners

Revenue. Revenue decreased $2.0 million, or 1%, for the three months ended June 30, 2007, compared to the corresponding period of 2006. Oklahoma revenues increased $13.2 million primarily due to increased volumes from its Woodford gathering system, which began operation in December 2006. Oklahoma increases were offset by decreases in East Texas of $6.5 million to the decrease primarily because of a contractual change from a purchasing contract to a processing contract at its Carthage facility in the third quarter of 2006. Additionally, Other Southwest experienced a decline in revenue of $4.6 million primarily attributed to a change in the contract mix at its Appleby facility, from purchasing contracts to gathering contracts, which occurred in the third quarter of 2006.

Derivative (Loss) Gain. Loss from derivative instruments increased $0.5 million, during the three months ended June 30, 2007, compared to the corresponding period in 2006. The mark-to-market adjustments of the Partnership’s derivative instruments resulted in a $1.0 million non-cash increase in unrealized losses, which were partially offset by an increase in realized gains of $0.5 million from settlements, when comparing 2007 to 2006 results.

Purchased product costs. Purchased product costs decreased $2.0 million, or 3%, for the three months ended June 30, 2007, compared to the corresponding period of 2006. The decrease in purchased product costs is directly related to the change in contract types that drove a decrease in revenue for the quarter.

Facility Expenses. Facility expenses increased $5.1 million, or 34%, during the three months ended June 30, 2007, compared to the corresponding period in 2006. The increase in the Oklahoma segment of $3.5 million was primarily due to the addition of the Woodford and Grimes gathering systems and included $0.8 million of weather related repairs. The Partnership’s Gulf Coast business unit facility expenses increased $1.1 million attributable to increases in wages and salaries, chemical costs and contract engineering for special projects.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $3.5 million, or 39%, during the three months ended June 30, 2007, relative to the comparable period in 2006. $2.3 million of the increase resulted from higher non-cash equity-based compensation expense. Of this amount, $2.2 million is attributable to the Participation Plan, with the balance attributable to restricted units. Participation Plan compensation expense is determined based on the formula-based increase in the value of the General Partner. The formula is based on the market price of the Partnership’s common units, the current quarterly per-unit distribution rate and the dollar amount of the quarterly distribution to the General Partner. An additional $1.8 million resulted from additional professional fees and consulting

services. Finally, the Partnership experienced a one-time charge to terminate the old headquarters lease of $0.9 million in the second quarter of 2006.

Earnings from Unconsolidated Affiliates. Earnings from unconsolidated affiliates is primarily related to the Partnership’s investment in Starfish, a joint venture with Enbridge Offshore Pipelines L.L.C. The Partnership accounts for its 50% interest using the equity method, and the financial results for Starfish are included as earnings from unconsolidated affiliates. During the three months ended June 30, 2007, earnings from unconsolidated affiliates increased $0.4 million, or 35%, relative to the comparable period in 2006. The increase was primarily due to systems operating at full capacity in 2007 compared to limited capacities in 2006 from hurricane damage and fewer hurricane-related expenses.

Interest Expense. Interest expense decreased $1.7 million, or 16%, during the three months ended June 30, 2007, relative to the comparable period in 2006, primarily due to a reduction of interest expense for the capitalization of interest related to construction in progress of $1.1 million.

Miscellaneous (Expense) Income. Miscellaneous expense increased $2.0 million, or 130%, during the three months ended June 301, 2007, relative to the comparable period in 2006. This increase was primarily due to $2.6 million of income from insurance recoveries in the second quarter of 2006, compared to zero in 2007. The increase was partially offset by a decrease in Starfish insurance premiums of $0.3 million in the second quarter of 2007 compared to the same period in 2006.

Six months ended June 30, 2007, compared to the six months ended June 30, 2006

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners				Consolidating Entries				Total
Six months ended June 30, 2007:
Revenue:
Revenue		$	125,085			$	265,572			$	(38,367	)	$	352,290
Derivative loss		(13,530		)		(14,292		)		—			(27,822		)
Total revenue		111,555				251,280				(38,367		)	324,468
Purchased product costs		101,520				138,218				(26,024		)	213,714
Net operating margin		10,035				113,062				(12,343		)	110,754
Operating expenses:
Facility expenses		9,775				33,259				(12,557		)	30,477
Selling, general and administrative expenses		13,218				26,317				—			39,535
Depreciation		586				16,913				—			17,499
Amortization of intangible assets		—				8,336				—			8,336
Accretion of asset retirement and lease obligations		—				55				—			55
(Loss) income from operations		(13,544		)		28,182				214			14,852
Other income (expense):
Earnings from unconsolidated affiliates		—				3,423				—			3,423
Interest income		1,121				2,399				—			3,520
Interest expense		(122		)		(18,346		)		—			(18,468		)
Amortization of deferred financing costs (a component of interest expense)		(129		)		(1,322		)		—			(1,451		)
Dividend income		258				81				—			339
Miscellaneous expense		(145		)		(1,261		)		—			(1,406		)
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(12,561		)		13,156				214			809
Non-controlling interest in net income of consolidated subsidiary		—				—				(9,522		)	(9,522		)
Interest in net income of consolidated subsidiary		3,612				—				(3,612		)	—
(Loss) income before income taxes		(8,949		)		13,156				(12,920		)	(8,713		)
Provision for income tax benefit (expense)		2,420				(125		)		103			2,398
Net (loss) income		$	(6,529	)		$	13,031			$	(12,817	)	$	(6,315	)

	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners				Consolidating Entries				Total
Six months ended June 30, 2006:
Revenue:
Revenue		$	164,281			$	298,783			$	(35,594	)	$	427,470
Derivative loss		(7,655		)		(6,661		)		—			(14,316		)
Total revenue		156,626				292,122				(35,594		)	413,154
Purchased product costs		144,527				177,205				(23,581		)	298,151
Net operating margin		12,099				114,917				(12,013		)	115,003
Operating expenses:
Facility expenses		10,579				29,229				(12,013		)	27,795
Selling, general and administrative expenses		7,111				17,326				—			24,437
Depreciation		599				14,557				—			15,156
Amortization of intangible assets		—				8,043				—			8,043
Accretion of asset retirement and lease obligations		—				51				—			51
(Loss) income from operations		(6,190		)		45,711				—			39,521
Other income (expense):
Earnings from unconsolidated affiliates		—				2,173				—			2,173
Interest income		363				479				—			842
Interest expense		(152		)		(21,690		)		—			(21,842		)
Amortization of deferred financing costs (a component of interest expense)		(50		)		(1,634		)		—			(1,684		)
Dividend income		215				—				—			215
Miscellaneous income		152				3,607				—			3,759
(Loss) income before non-controlling interest in net income of consolidated subsidiary and income taxes		(5,662		)		28,646				—			22,984
Non-controlling interest in net income of consolidated subsidiary		—				—				(21,817		)	(21,817		)
Interest in net income of consolidated subsidiary		6,693				—				(6,693		)	—
Income before income taxes		1,031				28,646				(28,510		)	1,167
Provision for income tax expense		(331		)		(679		)		543			(467		)
Net income		$	700			$	27,967			$	(27,967	)	$	700

MarkWest Hydrocarbon Standalone

Revenue. Revenue decreased $39.2 million, or 24%, for the six months ended June 30, 2007, compared to the corresponding period in 2006. We experienced a $35.7 million decrease in our wholesale business attributable to the expiration of a marketing arrangement, resulting in the dissolution of our wholesale business in the fourth quarter of 2006. A $14.3 million decrease in our gas marketing business was primarily due to lower volumes of 9,800 MMBtu/d, which were slightly offset by higher prices of $0.01 per MMBtu. Additionally, the revaluation of our long-term shrink obligation decreased revenue by $7.1 million in the six months ended June 30, 2007, compared to the same period in 2006. These decreases were partially offset by an increase in our frac spread NGL revenues of $18.2 million, primarily the result of increases in prices ($0.72 per gallon) and volumes (56,000 Gal/d).

Derivative (Loss) Gain. Losses from derivative instruments increased $5.9 million during the six months ended June 30, 2007 compared to the corresponding period in 2006. This loss was primarily due to unrealized losses of $7.7 million resulting from mark-to-market adjustments, partially offset by a $1.9 million increase in realized gains from settlements, when comparing 2007 to 2006 results.

Purchased Product Costs. Purchased product costs decreased $43.0 million, or 30%, for the six months ended June 30, 2007, compared to the corresponding period in 2006. The decrease was primarily due a $35.7 million decrease in purchased product costs in our wholesale business, attributable to the expiration of a marketing arrangement resulting in the dissolution of our wholesale business in the fourth quarter of 2006. Our natural gas marketing business reflected a decrease of $14.4 million, primarily due to a decrease in prices and volumes. Additionally, we recorded a decrease in our frac spread purchase product costs of $2.4 million, resulting primarily from decreased prices. Losses from derivative instruments increased $3.0 million. The increased loss was made up of an additional $1.8 million of unrealized loss and $1.2 million of realized loss. Finally, the value of a certain contract is marked-to-market based on an index price through purchased product costs, which resulted in an additional $1.7 million increase in unrealized losses.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $6.1 million, or 86%, during the six months ended June 30, 2007, compared to the corresponding period in 2006. $4.9 million is attributable to the Participation Plan. Participation Plan compensation expense is determined based on the formula-based increase in the value of the General Partner. The formula is based on the market price of the Partnership’s common units, the current quarterly per-unit distribution rate and the dollar amount of the quarterly distribution to the General Partner. Additionally, we experienced an increase in professional and consulting service costs of $1.1 million.

MarkWest Energy Partners

Revenue. Revenue decreased $33.2 million, or 11%, for the six months ended June 30, 2007, compared to the corresponding period of 2006, mostly due to the conversion of contracts. East Texas contributed $16.9 million to the decrease primarily because of a contractual change from a purchasing contract to a processing contract at its Carthage facility in the third quarter of 2006, which left lower volumes available for resale. Additionally, Other Southwest experienced a decline in revenue of $14.7 million, primarily attributed to a change in the contract mix at its Appleby facility, from purchasing contracts to gathering contracts, which occurred in the third quarter of 2006.

Derivative (Loss) Gain. Loss from derivative instruments increased $7.6 million during the six months ended June 30, 2007, compared to the corresponding period in 2006. The mark-to-market adjustments of the Partnership’s derivative instruments resulted in a $10.4 million increase in unrealized losses, which were partially offset by an increase in realized gains of $2.8 million from settlements, when comparing 2007 to 2006 results.

Purchased product costs. Purchased product costs decreased $39.0 million, or 22%, for the six months ended June 30, 2007, compared to the corresponding period of 2006. The decrease in purchased product costs is directly related to the change in contract types that drove a decrease in revenue for the reporting period.

Facility Expenses. Facility expenses increased $4.0 million, or 14%, during the six months ended June 30, 2007, compared to the corresponding period in 2006. The increase is primarily attributable to a $5.0 million increase from the Oklahoma segment related to the addition of the Woodford and Grimes gathering systems and a $0.7 million increase in the East Texas segment from increased compression and tax expenses. The increases were partially offset by a $2.4 million decrease in the Gulf Coast Business Unit, resulting from a utility refund of $3.6 million from a rate case concluded in the first quarter of 2007; the refund was partially offset by a $0.6 million increase related to increased payroll and contract engineering expenses.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $9.0 million, or 52%, during the six months ended June 30, 2007, relative to the comparable period in 2006. $6.5 million of the increase can be attributed to higher non-cash equity-based compensation expense. Of this amount, $5.9 million is attributable to the Participation Plan, with the balance to restricted units. Participation Plan compensation expense is determined based on the formula-based increase in the value of the General Partner. The formula is based on the market price of the Partnership’s common units, the current quarterly per-unit distribution rate and the dollar amount of the quarterly distribution to the General Partner. In addition, we incurred increased expense associated with labor and benefits of $1.1 million and increased professional fees and consulting services of $2.1 million. Finally, we experienced a one-time charge to terminate the old headquarters lease of $0.9 million reported in 2006.

Earnings from Unconsolidated Affiliates. Earnings from unconsolidated affiliates are primarily related to the Partnership’s investment in Starfish, a joint venture with Enbridge Offshore Pipelines L.L.C. The Partnership accounts for its 50% interest using the equity method, and the financial results for Starfish are included as earnings from unconsolidated affiliates. During the six months ended June 30, 2007, the Partnership’s earnings from unconsolidated affiliates increased $1.3 million, or 58%, relative to the comparable period in 2006. The increase was primarily due to systems operating at full capacity in 2007 compared to limited capacities in 2006 resulting from hurricane damage and fewer hurricane related expenses.

Interest Income. Interest income increased $1.9 million, during the six months ended June 30, 2007, relative to the comparable period in 2006, primarily due to the proceeds received from a rate case that concluded in the first quarter of 2007 in our Gulf Coast Business Unit.

Interest Expense. Interest expense decreased $3.3 million, or 15%, during the six months ended June 30, 2007, relative to the comparable period in 2006, primarily due to a reduction of interest expense for the capitalization of interest related to construction in progress of $2.3 million.

Miscellaneous (Expense) Income. Miscellaneous expense increased $4.8 million during the six months ended June 30, 2007, relative to the comparable period in 2006. This increase was primarily due to $4.4 million of income from insurance recoveries in 2006, compared to only $0.2 million in 2007, as well as an increase in Starfish insurance premiums of $0.6 million in 2007 compared to 2006.

Liquidity and Capital Resources

MarkWest Hydrocarbon Standalone

Our primary source of liquidity to meet operating expenses and fund capital expenditures is cash flow from operations, principally from the marketing of NGL and quarterly distributions received from MarkWest Energy Partners. We believe that cash flow from operations and distributions from the Partnership will be sufficient to fund capital expenditures and other working capital expenditures for the foreseeable future.

On October 13, 2006, the Company completed the repurchase of a 0.5% interest in the general partner. This purchase resulted in an increase in our ownership level in the general partner to 89.7%. As of December 31, 2006, we still owned 89.7% of the general partner of MarkWest Energy Partners, excluding interests held by certain employees and directors but deemed owned by the Company through the Participation Plan. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13% of all cash distributed in a quarter after each unit has received $0.275 for that quarter; 23% of all cash distributed after each unit has received $0.3125 for that quarter; and 48% of all cash distributed after each unit has received $0.375 for that quarter. For the six months ended June 30, 2007, we received $2.6 million in distributions from our limited units and $6.2 million from our general partner interest, of which $5.7 million represented payments on incentive distribution rights.

Cash flows generated from our NGL marketing and natural gas supply operations are subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are enhanced in periods when NGL prices are high relative to the price of the natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia. Conversely, they are reduced in periods when the NGL prices are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep-whole” the producers for the energy content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. Periodically, natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, and the cost of keeping the producer “whole” can result in operating losses.

Debt

In October 2004, the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility has a variable interest rate based on the base rate or the London Inter Bank Offering Rate (“LIBOR”), as discussed below. In October, November and December 2005, the Company entered into the first, second and third amendments to the credit agreement. The first amendment to the credit facility extended the term of the original agreement to November 15, 2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million is committed to a letter of credit, leaving $10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006, and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving $7.5 million available for revolving loans. On January 31, 2006, the Company entered into the first amended and restated credit agreement which reinstated the maximum lending limit of $25.0 million for a one year term. On August 18, 2006, the Company entered into the second amended and restated credit facility which increased the size of the facility from $25.0 million to $55.0 million, increasing the term of the agreement to three years and allowing the flexibility for MarkWest Hydrocarbon to directly invest in additional units of MarkWest Energy Partners to fund future growth opportunities.

On February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement, increasing the term by one year to August 20, 2010, and providing an additional $50.0 million of credit to enable the Company to meet potential margin requirements associated with its derivative instruments.

On March 15, 2007, the Company entered into the second amendment to the second amended and restated credit agreement. This amendment clarifies language relating to the swap contracts between the Company and the Lenders or Lender’s affiliates in several sections of the Company Credit Agreement. It provides that the Non-Borrowing Base Credit Extension, as defined in the agreement, shall be used solely for the purpose of enabling the Company to meet margin requirements under Swap Contracts, as defined in the agreement, with counterparties which are not lenders or affiliates of the lenders.

The Company Credit Facility bears interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the 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 Facility’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75% for Eurodollar Rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.

Under the provisions of the credit facility, the Company is subject to a number of restrictions on its business, including its ability to grant liens on assets; make or own certain investments; enter into any swap contracts other than in the ordinary course of business; merge, consolidate or sell assets; incur indebtedness (other than subordinated indebtedness); make distributions on equity investments; declare or make, directly or indirectly, any restricted distributions.

At June 30, 2007, we had no debt outstanding on the Company Credit Facility and $28.0 million available for borrowing.

We have budgeted capital expenditures of $3.6 million for 2007, principally for computer hardware and software upgrades. We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners and projected cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

MarkWest Energy Partners

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

Credit Facility

The Partnership’s wholly owned subsidiary MarkWest Energy Operating Company, L.L.C. has a $250 million dollar revolving credit facility (the “Credit Facility”). The Credit Facility is guaranteed by the Partnership and all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the Credit Facility bear interest at a variable interest rate, plus basis points. The basis points vary based on the ratio of the Partnership’s consolidated debt to consolidated EBITDA, as defined in the Fifth Amendment to the Credit Facility. For the six months ended June 30, 2007 the weighted average interest rate on the Credit Facility was 7.58%.

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants as defined in the Fifth Amendment to the Credit Facility. These covenants are used to calculate the available borrowing capacity on a quarterly basis, as of June 30, 2007, available borrowings under the Credit Facility was $216.4 million.

Senior Notes

At March 31, 2007, the Partnership and its wholly owned subsidiary, MarkWest Energy Finance Corporation, had two series of senior notes outstanding: $225.0 million at a fixed rate of 6.875% due in November 2014 (the “2014 Notes”) and $272.0 million, net of unamortized discount of $3.0 million, at a fixed rate of 8.5% due in July 2016 (the “2016 Notes”), together (the “Senior Notes”). The estimated fair value of the Senior Notes was approximately $485.9 million and $499.8 million at June 30, 2007 and December 31, 2006, respectively, based on quoted market prices.

The Partnership has no independent assets or operations. Each of the Partnership’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed 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 its Credit Facility.

On April 9, 2007, the Partnership completed a private placement of 4.1 million common units. The units were issued at a purchase price of $32.98 per unit. The sale of units resulted in net proceeds of $137.7 million, including the general partner’s contribution to maintain its 2% general partner interest of $2.8 million, after legal, accounting and other transaction expenses. The Partnership will use the net proceeds from the offering to fund capital expenditure requirements. The common units were registered on July 11, 2007, subsequent to the period covered by this report.

The Partnership’s ability to pay distributions to its unitholders and to fund planned capital expenditures and make acquisitions will depend upon its future operating performance. That, in turn, will be affected by prevailing economic conditions in the Partnership’s industry, as well as financial, business and other factors, some of which are beyond its control.

The Partnership has budgeted approximately $290 million for expenditures in 2007, which includes $6.0 million for maintenance capital. It plans to use from $180 million to $200 million of its expansion capital budget to fund the construction of the Woodford gathering system. As of June 30, 2007, the Partnership has $153 million remaining in its budget including $4.2 million for maintenance capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of Partnership assets, or facilitate an increase in volumes within its operations, whether through construction or acquisition. Maintenance capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

Cash Flows

The following table summarizes cash inflows (outflows) for the six months ended June 30, 2007 and 2006 (in thousands):

	Six months ended June 30,
Cash Flows	2007			2006
Net cash flows provided by operating activities	$	32,364		$	86,594
Net cash flows used in investing activities	(140,727		)	(47,640		)
Net cash flows provided by (used in) financing activities	99,428			(33,650		)

Net cash provided by operating activities decreased $54.3 million during the six months ended June 30, 2007, compared to the corresponding period in 2006. The change resulted from a decrease in operating cash flows provided by working capital of $45.9 plus $15.8 million of purchase of marketable securities. The reductions of operating cash flows were partially offset by distributions of $6.2 million in from the Partnership’s equity investment in Starfish and a $5.5 million refund from a Partnership rate case concluded in the first quarter of 2007. The change in working capital was primarily a result of variances in the timing of accounts receivable collections and payments on accounts payable.

Net cash used in investing activities increased by $93.0 million during the six months ended June 30, 2007, compared to the same period in 2006. The increase was due to capital expenditures primarily from the development of the Partnership’s Woodford gathering system, where it invested approximately $90.3 million of expansion capital.

Net cash provided by financing activities increased $133.1 million during the during six months ended June 30, 2007, compared to the same period in 2006, primarily due to proceeds received from MarkWest Energy’s private placement of $135.0 million. The increase was offset by distributions to the Partnership’s unitholders increasing to $29.8 million in the first half of 2007 from $17.6 million in the first half of 2006; and dividends to shareholders increased to $7.4 million during the six months ended June 30, 2007 compared to $3.4 million in the comparable period in 2006.

Matters Impacting Future Results

During August and September 2005, Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. Operations of our unconsolidated affiliate, Starfish Pipeline Company were nominally impacted by Hurricane Katrina but were significantly impacted by Hurricane Rita. We are continuing to submit insurance claims on an on-going basis relating to both business interruption and property damage. As of June 30, 2007 we have recorded a receivable of $12.4 million for insurance recoveries with respect to our property loss and business interruption claims, and we anticipate additional recoveries for expenses and losses incurred as repairs proceed.

The loss to both offshore and onshore assets resulting from Hurricanes Katrina and Rita produced substantial insurance claims within the oil and gas industry. Along with other industry participants, the Partnership has seen its insurance costs increase substantially within this region as a result of these developments. The Partnership has mitigated a portion of the cost increase by reducing its coverage and adding a broader self-insurance element to its overall coverage.

The Partnership’s affiliate, MarkWest Energy Appalachia, L.L.C. (“MEA”) operates the Appalachia Liquids Pipeline System (“ALPS”) to transport NGLs from its Maytown gas processing plant to its Siloam fractionator. A segment of the ALPS pipeline, which runs from the Maytown plant to the Ranger Junction, West Virginia, is owned by Equitable Production Company, but is leased and operated by MEA. As part of its ongoing operation of the ALPS pipeline, MEA implemented an in-line inspection program on this leased segment of the ALPS pipeline. Data from its in-line inspection indicated areas of external corrosion and other defects in a four-mile section of pipeline, and as a result MEA idled the Maytown to Ranger segment. The in-line inspection data coupled with other information MEA has gathered is being reviewed and MEA is working with Equitable to determine what the most appropriate corrective action may be. Possible corrective action may include refitting the existing pipe or shutting in the ALPS pipeline and building a new pipeline. If the partnership had determined it would shut in the ALPS pipeline as of June 30, 2007, it would have recognized a $6.0 million impairment to write-off the net book value of the leasehold improvements. In the interim, MEA is trucking the NGLs produced from the Maytown plant to the Siloam fractionation facility while MEA is maintaining this segment of the ALPS pipeline in idle status. As a result, operations have not been interrupted. The additional transportation costs associated with the

trucking are not expected to have material adverse effect on our results of operations or financial positions.

MarkWest Hydrocarbon, Inc. is a corporation for federal income tax purposes. As such, our federal taxable income is subject to tax at a maximum rate of 35.0% under current law and a blended state rate of 2.8%, net of Federal benefit. We expect to have future taxable income allocated to us as a result of our investment in the Partnership and from our Appalachia processing agreements.

We anticipate using all of the Federal net operating loss carryforwards from previous years for the year ended December 31, 2006 when we file our 2006 tax return later this year. As a result, the amount of money available to provide dividends to our stockholders will decrease for future distributions.

Critical Accounting Policies

Our condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Preparation of these statements requires management to make significant judgments and estimates. Some accounting policies have a significant impact on amounts reported in these financial statements.

The Company adopted the FASB issued Interpretation Number 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), effective January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards Number 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a “more likely than not” recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. For the impact of FIN 48 on the Company’s financial statements, see Note 9 to the condensed consolidated financial statements.

Except for the adoption of FIN 48, there have been no significant changes in critical accounting policies or management estimates since the year ended December 31, 2006. A comprehensive discussion of our critical accounting policies and management estimates is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K/A for the year ended December 31, 2006.

Recent Accounting Pronouncements

Refer to Note 3 of the 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 manage volatility in our cash flows. We have a committee comprised of the senior management team that oversees all of the risk management activity and continually monitors our hedging program and we expect to continue to adjust our hedge position as conditions warrant. We use mark-to-market accounting for our non-trading commodity derivative instruments, accordingly, the volatility in any given period related to unrealized gains or losses can be significant to our

overall financial results; however, we ultimately expect those gains and losses to be offset when they become realized. We do not have any trading derivative financial instruments.

We utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options on the over-the-counter (“OTC”) market. The Company may also enter into futures contracts traded on the New York Mercantile Exchange (“NYMEX”). Swaps and futures 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 enter into OTC swaps with financial institutions and other energy company counterparties. 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) and NYMEX positions.

Because of the strong correlation between NGL prices and crude oil prices and limited liquidity in the NGL financial market, we use crude oil derivative instruments to hedge NGL price risk. As a result of these transactions, we have mitigated our expected commodity price risk with agreements expiring at various times through the third quarter of 2010. The margins earned from condensate sales are directly correlated with crude oil prices. A committee comprised of the senior management team oversees all of the risk management activity and continually monitors the risk management program and expects to continue to adjust our financial positions as conditions warrant.

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 requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that we enter into derivative instruments, we may be prevented from realizing the benefits of favorable price changes in the physical market. We are similarly insulated, however, against unfavorable changes in such prices.

We changed the disclosure alternative for reporting our commodity derivatives in the second quarter of 2007 from a tabular presentation to a sensitivity analysis. The change in the presentation format was made to simplify and enhance the information presented.

Considering the effects of derivative instruments and the effects of our commodity price exposures on production, a hypothetical $5 per barrel decrease in the market prices for crude oil could result in an estimated decrease of $4.8 million to operating cash flows for the remainder of 2007. Similarly, a $1 per MMBtu decrease in the market prices for natural gas could result in an estimated increase of $3.0 million to operating cash flows for the remainder of 2007. We consider the stated hypothetical changes in commodity prices to be reasonable given current and historic market performance. The sensitivity analysis presented does not consider the actions management may take to mitigate our exposure to changes, nor do they consider the effects that such hypothetical adverse changes may have on overall economic activity. Actual changes in market prices may differ from hypothetical changes. The effect of the stated theoretical change represents potential losses in our condensed consolidated financial position and results of operations.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of June 30, 2007, an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 (the “Exchange Act”)). Based on that evaluation, the Company’s management, including the Chief Executive Officer and Chief Financial Officer, concluded the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company 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 Company’s management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

In May 2007, the Company 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 Company. 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 Company believes that this new system will strengthen its internal controls over financial reporting, there are inherent risks in implementing any new system and the Company 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 Company’s internal controls over financial reporting.

Except as described above, there were no other changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2007, that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are subject to a variety of risks and disputes, and are a party to various legal proceedings in the normal course of 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 Company or the Partnership (collectively 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 the ALPS Pipeline, a natural gas liquids (NGL) pipeline owned by Equitable Production Company and leased and operated by the Partnership’s 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 responds to a motion to dismiss one of the counts of violations, which count involves $825,000 of the $1,070,000 proposed penalty. This count arises out of alleged activity in 1982 and 1987, which predates MarkWest’s leasing and operation of the pipeline. MarkWest believes it has viable defenses to the remaining counts and will vigorously defend all applicable assertions of violations at the hearing.

Related to the above referenced 2004 pipeline explosion and fire incident, MarkWest Hydrocarbon and the Partnership have filed an action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed to the U.S. District Court for the District of Colorado, (Civil Action No. 1:05-CV-1948, on October 7, 2005) against their All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain costs related to the pipeline incident. The costs include internal costs incurred for damage to, and loss of use of the pipeline, equipment and products; extra transportation costs incurred for transporting the liquids while the pipeline was out of service; reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). Following initial discovery, MarkWest was granted leave of the Court to amend its complaint to add a bad faith claim and a claim for punitive damages. The Partnership has not provided for a receivable for any of the claims in this action because of the uncertainty as to whether and how much it will ultimately recover under the policies. The costs associated with this claim have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if and when it is received. The Defendant insurance companies and MarkWest have each filed separate summary judgment motions in the action and these motions are pending with the Court. Discovery in the action is also continuing.

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, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28TH Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), 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 Gonzales action was settled in early 2006 pursuant to a mediation held December 9, 2005. The other 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.

In February 2007, the Company learned that a default judgment had been entered against it in May 2006, in an action entitled Runyan v. Eclipse Realty LLC et al, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and complaint and was not given any notification of a motion for default judgment. The action involved a personal injury claim by an individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. On April 4, 2007, the Court granted the Company’s motion to set aside the default judgment and also granted the Company’s motion to dismiss MarkWest from the action entirely.

In the ordinary course of business, we are 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 our financial condition, liquidity or results of operations.

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

At the close of business on April 13, 2007, the record date for the determination of shareholders entitled to vote at the Company’s annual meeting, there were 11,993,096 shares of the Company’s common stock outstanding. At the annual meeting of stockholders held on June 13, 2007, there were not less than 11,434,699 shares, or approximately 95.3% of the outstanding stock, represented at the meeting and by proxy, therefore establishing the presence of a quorum. The Company’s shareholders were presented with and asked to vote on two proposals. The following are the results of the voting:

Proposal No. 1:

The election of Michael L. Betty, William A. Kellstrom, and William F. Wallace as Class II Directors for a term expiring at the Annual Meeting of Stockholders in the year 2010:

	Number of votes
Director Nominees	For	Authority Withheld
Michael L. Betty	11,395,797		38,902
William A. Kellstrom	11,293,779		140,920
William F. Wallace	11,379,010		55,689

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

Proposal No. 2:

The ratification of Deloitte & Touche LLP as the Company’s independent accountants for the fiscal year ending December 31, 2007:

For:		11,397,802
Against:		28,342
Abstained:		8,554

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

In accordance with the above, each of the nominees for election to the Board of Directors has received the requisite number of votes required for election and proposal number two received the requisite number of votes for approval. Accordingly, Mr. Betty, Mr. Kellstrom, and Mr. Wallace have been elected as Class II Directors to serve for a term expiring at the Annual Meeting of Stockholders in the year 2010. In addition, the selection of Deloitte & Touche LLP as the Company’s independent registered public accountants for the fiscal year ending December 31, 2007, was ratified.

Item 6. Exhibits

4.2(1)		Unit Purchase Agreement dated April 9, 2007 by and among MarkWest Energy Partners, L.P., MarkWest Energy G.P., L.L.C., and each of Kayne Anderson MLP Investment Company, GPS Income Fund, L.P., GPS High Yield Equities Fund, L.P., GPS New Equity Fund, L.P., Agile Performance Fund, L.L.C., Tortoise Energy Infrastructure Corporation, Tortoise Energy Capital Corporation, Royal Bank of Canada, Structured Finance Americas, L.L.C., The Cushing MLP Opportunity Fund I, L.P., and ZLP Fund, L.P. as purchasers.
4.3(1)		Registration Rights Agreement dated April 9, 2007 by and between MarkWest Energy Partners, L.P., and each of Kayne Anderson MLP Investment Company, GPS Income Fund, L.P., GPS High Yield Equities Fund, L.P., GPS New Equity Fund, L.P., Agile Performance Fund, L.L.C., Tortoise Energy Infrastructure Corporation, Tortoise Energy Capital Corporation, Royal Bank of Canada, Structured Finance Americas, L.L.C., The Cushing MLP Opportunity Fund I, L.P., and ZLP Fund, L.P. as purchasers.
10.1(2)		First Amendment to the Second Amended and Restated Credit Agreement, entered into as of February 16, 2007 by and between MarkWest Hydrocarbon, Inc. as Borrower, MarkWest Energy GP, L.L.C. as Guarantor, Sun Trust Bank, US Bank National Association and Bank of Oklahoma, N.A. as Lenders, and Royal Bank of Canada as Administrative Agent, Collateral Agent, L/C Issuer and Lender, to the $50,000,000 Credit Agreement.
10.2(3)		Second Amendment to the Second Amended and Restated Credit Agreement, entered into as of March 15, 2007 by and between MarkWest Hydrocarbon, Inc. as Borrower, MarkWest Energy GP, L.L.C. as Guarantor, Sun Trust Bank, US Bank National Association and Bank of Oklahoma, N.A. as Lenders, and Royal Bank of Canada as Administrative Agent, Collateral Agent, L/C Issuer and Lender, to the $50,000,000 Credit Agreement.
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.

(1) Incorporated by reference to MarkWest Energy Partner’s Current Report on Form 8-K, filed with the Commission on April 11, 2007.

(2) Incorporated by reference to MarkWest Hydrocarbon’s Current Report on Form 8-K, filed with the Commission on February 23, 2007.

(3) Incorporated by reference to MarkWest Hydrocarbon’s Current Report on Form 8-K, filed with the Commission on March 20, 2007.

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 HYDROCARBON, INC.
	(Registrant)
Date: August 8, 2007	/s/ FRANK M. SEMPLE
	Frank M. Semple
	President and Chief Executive Officer
	(Principal Executive Officer)
Date: August 8, 2007	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)