PART I—FINANCIAL INFORMATION


Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets at March 31, 2007 and December 31, 2006
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2007 and 2006
	Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2007 and 2006
	Condensed Consolidated Statement of Changes in Stockholders’ Equity for the three months ended March 31, 2007
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and 2006
	Notes to the Condensed Consolidated Financial Statements

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures about Market Risk
Item 4.	Controls and Procedures

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings
Item 6.	Exhibits

SIGNATURES

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)

	March 31,			December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	82,829		$	48,844
Marketable securities	8,626			7,713
Receivables, net of allowances of $159 and $156, respectively	108,249			101,116
Inventories	16,813			35,261
Fair value of derivative instruments	1,985			9,938
Other current assets	13,860			15,264
Total current assets	232,362			218,136

Property, plant and equipment	715,957			662,606
Less: accumulated depreciation, depletion, amortization and impairment	(116,358		)	(108,271		)
Total property, plant and equipment, net	599,599			554,335

Other assets:
Investment in Starfish	63,319			64,240
Intangibles, net of accumulated amortization of $33,248 and $29,080 respectively	339,227			344,066
Deferred financing costs, net of accumulated amortization of $6,169 and $5,462 respectively	15,558			16,079
Deferred contract cost, net of accumulated amortization of $780 and $702, respectively	2,470			2,548
Fair value of derivative instruments	4,331			2,794
Other long-term assets	1,043			1,043
Total other assets	425,948			430,770
Total assets	$	1,257,909		$	1,203,241

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	95,496		$	89,242
Accrued liabilities	45,512			55,208
Fair value of derivative instruments	8,400			7,476
Deferred income taxes	526			180
Total current liabilities	149,934			152,106

Deferred income taxes	8,872			9,553
Fair value of derivative instruments	10,828			1,460
Long-term debt, net of original issue discount of $3,053 and $3,135, respectively	576,947			526,865
Other long-term liabilities	38,787			30,196
Non-controlling interest in consolidated subsidiary	432,911			441,572

Commitments and contingencies (Note 11)

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, 11,993,096 and 11,975,256 shares issued, respectively	120			120
Additional paid-in capital	37,866			40,266
Accumulated other comprehensive income, net of tax	1,669			1,103
Treasury stock, 626 and 0 shares, respectively	(25		)	—
Total stockholders’ equity	39,630			41,489
Total liabilities and stockholders’ equity	$	1,257,909		$	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 March 31,
	2007			2006

Revenue:
Revenue	$	175,397		$	241,119
Derivative loss	(13,909		)	(1,259		)
Total revenue	161,488			239,860

Operating expenses:
Purchased product costs	104,207			181,628
Facility expenses	12,062			13,482
Selling, general and administrative expenses	20,715			11,376
Depreciation	8,174			7,378
Amortization of intangible assets	4,168			4,016
Accretion of asset retirement obligations	27			25
Total operating expenses	149,353			217,905

Income from operations	12,135			21,955

Other income (expense):
Earnings from unconsolidated affiliates	1,767			945
Interest income	2,396			406
Interest expense	(9,414		)	(11,044		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(720		)	(825		)
Dividend income	122			106
Miscellaneous (expense) income	(872		)	2,242
Income before non-controlling interest in net income of consolidated subsidiary and income tax (expense) benefit	5,414			13,785

Income tax (expense) benefit:
Current	(801		)	493
Deferred	304			(902		)
Income tax expense	(497		)	(409		)

Non-controlling interest in net income of consolidated subsidiary	(3,960		)	(10,544		)
Net income	$	957		$	2,832

Net income per share:
Basic	$	0.08		$	0.24
Diluted	$	0.08		$	0.24

Weighted average number of outstanding shares of common stock (March 31, 2006 adjusted to reflect May 23, 2006 stock dividend):
Basic	11,987			11,906
Diluted	12,043			12,019

Cash dividend declared per common share	$	0.320		$	0.159

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 March 31,
	2007		2006

Net income	$	957	$	2,832

Other comprehensive income:
Unrealized gains on marketable securities, net of tax of $346 and $115, respectively.	566		193

Comprehensive income	$	1,523	$	3,025

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 Earnings (Deficit)			Other Comprehensive Income		Treasury Stock			Total Stockholders’ Equity
December 31, 2006	11,975	—	$	120	$	40,266		$	—		$	1,103	$	—		$	41,489
Stock option exercises	1	—	—		4			—			—		—			4
Compensation expense related to restricted stock	—	—	—		199			—			—		—			199
Issuance of restricted stock	17	—	—		—			—			—		—			—
Treasury stock reacquired	—	1	—		25			—			—		(25		)	—
FAS 123R windfall pool under APIC	—	—	—		84			—			—		—			84
FIN 48 adjustment	—	—	—		—			(71		)	—		—			(71		)
Net income	—	—	—		—			957			—		—			957
Dividends paid	—	—	—		(2,712		)	(886		)	—		—			(3,598		)
Other comprehensive income	—	—	—		—			—			566		—			566
March 31, 2007	11,993	1	$	120	$	37,866		$	—		$	1,669	$	(25	)	$	39,630

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)

	Three months ended March 31,
	2007			2006
Cash flows from operating activities:
Net income	$	957		$	2,832
Adjustments to reconcile net income to net cash provided by operating activities (net of acquisitions):
Depreciation	8,174			7,378
Amortization of intangible assets	4,168			4,016
Amortization of deferred financing costs and original issue discount	720			825
Accretion of asset retirement obligation	27			25
Amortization of gas contract	78			78
Restricted unit compensation expense	959			458
Participation Plan compensation expense	7,591			1,496
Stock option compensation expense	—			21
Restricted stock compensation expense	199			105
Non-controlling interest in net income of consolidated subsidiary	3,960			10,544
Contribution of treasury shares to 401(k) benefit plan	—			43
Equity in earnings from unconsolidated affiliates	(1,767		)	(945		)
Distributions from equity investments	2,688			—
Unrealized losses on derivative instruments	16,708			1,798
Loss (gain) on sale of property, plant and equipment	145			(410		)
Deferred income taxes	(752		)	902

Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(7,133		)	38,376
Inventories	17,966			20,634
Other current assets	1,405			(5,606		)
Accounts payable and accrued liabilities	150			(27,038		)
Other long-term liabilities	357			92
Net cash flows provided by operating activities	56,600			55,624

Cash flows from investing activities:
Acquisitions	(46		)	(360		)
Investment in Starfish	—			(890		)
Capital expenditures	(55,002		)	(13,249		)
Proceeds from sale of property, plant and equipment	15			529
Net cash flows used in investing activities	(55,033		)	(13,970		)

Cash flows from financing activities:
Proceeds from long-term debt	135,500			25,000
Payments of long-term debt	(85,500		)	(44,000		)
Payments for debt issuance costs deferred financing costs and registration costs	(338		)	(105		)
Proceeds from MarkWest Energy’s private placement	—			5,000
Exercise of stock options	4			(1		)
SFAS 123R windfall pool under APIC	84			—
Payment of dividends	(3,598		)	(1,355		)
Distributions to MarkWest Energy unitholders	(13,734		)	(8,529		)
Net cash flows provided by (used in) financing activities	32,418			(23,990		)

Net increase in cash	33,985			17,664
Cash and cash equivalents at beginning of year	48,844			20,968
Cash and cash equivalents at end of period	$	82,829		$	38,632

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

	Three months ended March 31,
	2007		2006
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amount capitalized	$	11,930	$	5,319
Cash paid for income taxes	46		583

Supplemental schedule of non-cash investing and financing activities:
Construction projects in progress	3,316		405
Property, plant and equipment asset retirement obligation	142		64

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. 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 months ended March 31, 2007, are not necessarily indicative of results for the full year 2007, or any other future period.

The Company adopted the Financial Accounting Standards Board (“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 (“SFAS”) 109, Accounting for Income Taxes (“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. For the impact of FIN 48 on the Company’s financial statements, see Note 8.

On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. All common stock accounts and per share data for the period ended March 31, 2006 have been retroactively adjusted to give effect to the dividend of the Company’s common stock.

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 Number 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 SFAS 157 and expects to adopt this statement when required at the start of its fiscal year beginning January 1, 2008.

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. SFAS 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 SFAS 159 and expects to adopt this statement when required at the start of its fiscal year beginning January 1, 2008.

4. Equity Investment

The Partnership applies the equity method of accounting for its non-operating membership interest in Starfish Pipeline Company, LLC, (“Starfish”). Summarized financial information for 100% of Starfish is as follows (in thousands):

	Three months ended March 31,
	2007		2006

Revenues	$	8,513	$	5,097
Operating income	3,912		1,429
Net income	3,534		1,890

5. Property, Plant and Equipment

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

	March 31, 2007			December 31, 2006
Gas gathering facilities	$	298,166		$	289,586
Gas processing plants	217,380			217,080
Fractionation and storage facilities	23,516			23,470
Natural gas pipelines	42,361			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	20,836			20,705
Construction in progress	86,618			42,324
	715,957			662,606
Less: Accumulated depreciation	(116,358		)	(108,271		)
Total property, plant and equipment	$	599,599		$	554,335

The Company capitalizes interest on major projects during construction. For the three months ended March 31, 2007 and 2006, the Company capitalized interest of $1.2 million and $0.1 million, respectively.

6. Debt

Debt is summarized below (in thousands):

	March 31, 2007		December 31, 2006
MarkWest Hydrocarbon Credit Facility
8.75% interest	$	—	$	—

Partnership Credit Facility
7.71% at March 31, 2007 and 8.75% interest at December 31, 2006, due December 2010	80,000		30,000

Partnership Senior Notes
6.875% interest, due November 2014	225,000		225,000
8.5% interest, net of original issue discount of $3,053 and $3,135, respectively, due July 2016	271,947		271,865
Total long-term debt	$	576,947	$	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 three months ended March 31, 2007, the weighted average interest rate on the Credit Facility was 7.59%.

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, for the three months ended March 31, 2007, available borrowings under the Credit Facility were $168.4 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 $271.9 million, net of unamortized discount of $3.1 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 $505.5 million and $499.8 million at March 31, 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.

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.

7. 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 hedging program and expects to continue to adjust its hedge position as conditions warrant.

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 the lack of liquidity in the NGL financial market, the Company has used crude oil derivative instruments to hedge NGL price risk. As a result of these

transactions, the Company has hedged a significant portion of its expected natural gas and NGL commodity price risk through the first 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.

MarkWest Hydrocarbon Standalone

MarkWest Hydrocarbon may enter into physical and/or financial positions to manage its risks related to commodity price exposure for its Standalone segment. Due to 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 following tables summarize the current derivative positions specific to the MarkWest Hydrocarbon Standalone segment at March 31, 2007:

Fixed Physical Forward	Contract Period	Price (2)		Fair Value
				(in thousands)
Natural Gas - 6,308 MMBtu/d (sale)	Apr 2007	$	7.48	$	(91	)
Natural Gas - 28,091 MMBtu/d (sale)	May 2007	6.72		(1,203		)
Natural Gas - 4,665 MMBtu/d (sale)	Jun 2007	7.48		(100		)

Fixed Swaps (1)	Contract Period	Price (2)		Fair Value
				(in thousands)
Crude - 277 Bbl/d (sale)	Apr 2007	$	64.37	$	(17	)
Crude - 642 Bbl/d (sale)	Apr-Jun 2007	67.00		(30		)
Crude - 313 Bbl/d (sale)	Apr-Jun 2007	80.21		358
Crude - 36 Bbl/d (sale)	May 2007	64.62		(3		)
Crude - 241 Bbl/d (sale)	Jun 2007	65.32		(22		)
Crude - 1,323 Bbl/d (sale)	Jul 2007	65.68		(130		)
Crude - 1,396 Bbl/d (sale)	Aug 2007	65.99		(136		)
Crude - 1,547 Bbl/d (sale)	Sep 2007	66.26		(144		)
Crude - 2,504 Bbl/d (sale)	Oct 2007	66.48		(238		)
Crude - 2,766 Bbl/d (sale)	Nov 2007	66.70		(248		)
Crude - 3,916 Bbl/d (sale)	Dec 2007	66.91		(347		)
Crude - 4,361 Bbl/d (sale)	Jan 2008	67.04		(377		)
Crude - 3,913 Bbl/d (sale)	Feb 2008	67.14		(310		)
Crude - 2,320 Bbl/d (sale)	Mar 2008	67.23		(193		)

Natural Gas - 7,088 MMBtu/d (purchase)	Apr 2007	8.16		(59		)
Natural Gas - 86,850 MMBtu/d (purchase)	May 2007	8.08		(108		)
Natural Gas - 13,167 MMBtu/d (purchase)	Jun 2007	8.16		(13		)
Natural Gas - 12,581 MMBtu/d (purchase)	Jul 2007	8.29		(21		)
Natural Gas - 12,258 MMBtu/d (purchase)	Aug 2007	8.35		(7		)
Natural Gas - 4,833 MMBtu/d (purchase)	Sep 2007	8.38		(2		)

(1) Forward sales to hedge the Company’s production.

(2) A weighted average price is used for grouped positions.

The Company has also entered into a contract with one of the largest producers in the Appalachia region which creates a floor on the frac spread that can be realized on a specified volume purchased. Under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), the value of this contract is marked based on an index price through purchased product costs. As of March 31, 2007, the value of this contract was marked as a current liability of $1.8 million.

The following tables summarize the non-current derivative positions specific to the MarkWest Hydrocarbon Standalone segment at March 31, 2007:

Fixed Swaps (1)	Contract Period	Price (2)		Fair Value
				(in thousands)
Crude - 921 Bbl/d (sale)	Apr 2008	$	64.22	$	(155	)
Crude - 1,087 Bbl/d (sale)	May 2008	63.95		(196		)
Crude - 1,096 Bbl/d (sale)	Jun 2008	63.93		(191		)
Crude - 1,025 Bbl/d (sale)	Jul 2008	64.08		(178		)
Crude - 1,124 Bbl/d (sale)	Aug 2008	64.22		(188		)
Crude - 1,268 Bbl/d (sale)	Sep 2008	64.53		(192		)
Crude - 2,517 Bbl/d (sale)	Oct 2008	65.37		(329		)
Crude - 3,479 Bbl/d (sale)	Nov 2008	65.52		(417		)
Crude - 3,856 Bbl/d (sale)	Dec 2008	65.51		(462		)
Crude - 4,721 Bbl/d (sale)	Jan 2009	65.52		(548		)
Crude - 4,212 Bbl/d (sale)	Feb 2009	65.45		(438		)
Crude - 3,069 Bbl/d (sale)	Mar 2009	65.33		(351		)
Crude - 921 Bbl/d (sale)	Apr 2009	63.92		(133		)
Crude - 1,087 Bbl/d (sale)	May 2009	63.62		(166		)
Crude - 1,096 Bbl/d (sale)	Jun 2009	63.68		(156		)
Crude - 1,026 Bbl/d (sale)	Jul 2009	63.71		(144		)
Crude - 1,195 Bbl/d (sale)	Aug 2009	64.01		(152		)
Crude - 1,306 Bbl/d (sale)	Sep 2009	64.18		(150		)
Crude - 2,378 Bbl/d (sale)	Oct 2009	64.69		(237		)
Crude - 3,556 Bbl/d (sale)	Nov 2009	64.79		(322		)
Crude - 3,792 Bbl/d (sale)	Dec 2009	64.70		(349		)
Crude - 4,729 Bbl/d (sale)	Jan 2010	64.59		(431		)
Crude - 4,218 Bbl/d (sale)	Feb 2010	64.55		(341		)
Crude - 3,073 Bbl/d (sale)	Mar 2010	64.55		(262		)

Natural Gas - 4,070 MMBtu/d (purchase)	Apr 2008	8.05		35
Natural Gas - 15,873 MMBtu/d (purchase)	Apr-Jun 2008	8.01		365
Natural Gas - 5,361 MMBtu/d (purchase)	May 2008	7.93		45
Natural Gas - 5,482 MMBtu/d (purchase)	Jun 2008	7.98		46
Natural Gas - 15,755 MMBtu/d (purchase)	Jul 2008	8.05		123
Natural Gas - 15,701 MMBtu/d (purchase)	Jul-Sep 2008	8.10		389
Natural Gas - 15,755 MMBtu/d (purchase)	Aug 2008	8.11		127
Natural Gas - 16,280 MMBtu/d (purchase)	Sep 2008	8.16		130
Natural Gas - 4,070 MMBtu/d (purchase)	Apr 2009	7.64		38
Natural Gas - 15,883 MMBtu/d (purchase)	Apr-Jun 2009	7.61		399
Natural Gas - 5,361 MMBtu/d (purchase)	May 2009	7.51		52
Natural Gas - 5,482 MMBtu/d (purchase)	Jun 2009	7.56		53
Natural Gas - 15,755 MMBtu/d (purchase)	Jul 2009	7.60		155
Natural Gas - 15,710 MMBtu/d (purchase)	Jul-Sep 2009	7.73		369
Natural Gas - 15,755 MMBtu/d (purchase)	Aug 2009	7.69		141
Natural Gas - 16,280 MMBtu/d (purchase)	Sep 2009	7.78		125

(1) Forward sales to hedge the Company’s production.

(2) A weighted average price is used for grouped positions.

The impact of MarkWest Hydrocarbon Standalone’s commodity derivative instruments on its financial position is summarized below (in thousands):

	March 31, 2007		December 31, 2006
Fair value of derivative instruments:
Current asset	$	358	$	5,727
Non-current asset	2,592		35
Current liability	5,568		7,385
Non-current liability	6,488		98

MarkWest Energy Partners

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 expect 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. The volatility in any given period related to unrealized gains or losses can be significant to the overall financial results of the Partnership; however, the Partnership ultimately expect those gains and losses to be offset when they become realized.

The following tables summarize the Partnership’s current derivative positions at March 31, 2007:

Fixed Swaps (1)	Contract Period	Fixed Price (2)				Fair Value
						(in thousands)
Crude - 1,325 Bbl/d	Apr-Dec 2007	$	63.95			$	(1,736	)
Crude - 140 Bbl/d	Apr-Dec 2007	74.10				199

Basis Swaps	Contract Period					Fair Value
						(in thousands)
Natural Gas - 14,000 MMBtu/d	Apr-Oct 2007					$	(59	)

Options (puts) (3)	Contract Period	Floor				Fair Value
						(in thousands)
Ethane - 50,000 Gal/d	Apr-Dec 2007	$	0.65			$	(352	)

Collars (4)	Contract Period	Floor (2)		Cap (2)		Fair Value
						(in thousands)
Crude - 1,105 Bbl/d	Apr-Dec 2007	$	69.08	$	82.43	$	1,015
Crude - 1,476 Bbl/d	Jan-Mar 2008	69.76		79.01		413
Crude - 1,475 Bbl/d	Jan-Mar 2008	64.80		70.71		(261		)

Propane - 30,000 Gal/d	Apr-Jun 2007	0.96		1.16		(41		)
Propane - 30,000 Gal/d	Jul-Sep 2007	0.97		1.16		(85		)
Propane - 30,000 Gal/d	Oct-Dec 2007	0.98		1.18		—

(1) Forward sales to hedge the Partnership’s production.

(2) A weighted average price is used for grouped positions.

(3) Purchase of puts to hedge the Partnership’s Ethane production.

(4) Forward producer collars to hedge the Partnership’s production.

The Partnership has also entered into a contract which gives it an option to fix a component of the utilities cost to an index price on electricity at one of its plant locations. Under SFAS 133, the value of this contract is marked based on an index price through facilities expense. As of March 31, 2007, the value of this contract was marked as a long-term asset of $0.7 million and a short-term liability of $0.3 million.

The following tables summarize the Partnership’s non-current derivative positions at March 31, 2007:

Fixed Swaps (1)	Contract Period	Fixed Price (2)		Fair Value
				(in thousands)
Crude - 85 Bbl/d	Jan 2010	$	66.35	$	(4	)
Crude - 2,866 Bbl/d	Jan-Mar 2010	64.54		(744		)
Crude - 79 Bbl/d	Feb 2010	66.35		(3		)
Crude - 75 Bbl/d	Mar 2010	66.35		(3		)
Crude - 1,199 Bbl/d	Apr 2010	66.27		(42		)
Crude - 1,202 Bbl/d	May 2010	66.27		(40		)
Crude - 1,153 Bbl/d	Jun 2010	66.28		(32		)

Collars (3)	Contract Period	Floor (2)		Cap (2)		Fair Value
						(in thousands)
Crude - 1,473 Bbl/d	Apr-Jun 2008	$	69.48	$	78.66	$	375
Crude - 1,475 Bbl/d	Apr-Dec 2008	64.80		70.71		(790		)
Crude - 1,437 Bbl/d	Jul-Sep 2008	68.90		78.32		329
Crude - 1,473 Bbl/d	Oct-Dec 2008	68.41		77.85		304
Crude - 2,475 Bbl/d	Jan-Dec 2009	63.78		69.72		(2,096		)
Crude - 450 Bbl/d	Jan-Dec 2009	63.00		70.00		(586		)

(1) Forward sales to hedge the Partnership’s production.

(2) A weighted average price is used for grouped positions.

(3) Forward producer collars to hedge the Partnership’s production.

The impact of the Partnership’s commodity derivative instruments on its financial position are summarized below (in thousands):

	March 31, 2007		December 31, 2006
Fair value of derivative instruments:
Current asset	$	1,627	$	4,211
Non-current asset	1,739		2,759
Current liability	2,832		91
Non-current liability	4,340		1,362

8. 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 expense totaled $0.5 million for the three months ended March 31, 2007, resulting in an effective tax rate of 34.2%. Income tax benefit totaled $0.4 million for the comparable period in 2006, resulting in an effective tax rate of 13.0%. The 2007 estimated annual effective income tax rate varies from the statutory rate due to a change in the valuation allowance in the state not operating losses (“NOL”) mostly 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.

9. Stock and Incentive Compensation Plans

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

	Three months ended March 31,
	2007		2006
MarkWest Hydrocarbon
Stock options	$	—	$	21
Restricted stock	199		105
General partner interests under Participation Plan	7,591		1,509
Subordinated units under Participation Plan	—		(13		)
MarkWest Energy Partners
MarkWest Energy restricted units	959		458
Total compensation cost	$	8,749	$	2,080

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 March 31, 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.

			Weighted-
			average
			Remaining
			Vesting
	Amount		Period
	(in thousands)		(years)
Restricted stock	$	1,383	2.3
Restricted units	3,200		2.2
Total	$	4,583

Stock Options

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

	Three months ended March 31,
	2007	2006
Options exercised, cashless	—	7
Shares issued, cashless	—	4
Options exercised, cash	1	7
Shares issued, cash	1	5

For the three months ended March 31, 2007 and 2006 the Company received less than $0.1 million and $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	5.5 years
Risk free interest rates	4.35	%
Estimated volatility	46.50	%
Dividend yield	2.0	%

A summary of the status of the Company’s stock option plans as of March 31, 2007 and 2006, are presented below.

				Weighted-
				average
			Weighted-	Remaining	Aggregate
	Number of		average	Contractual	Intrinsic
	Shares		Exercise Price	Term	Value
Outstanding and Exercisable at December 31, 2006	65,635		7.48
Granted	—		—
Exercised	(679	)	6.79
Forfeited	—		—
Expired	—		—
Outstanding and Exercisable at March 31, 2007	64,956		7.49	5.0	$	3,638,397

	Three months ended March 31,
	2007		2006
Total fair value of options vested during the period	$	—	$	22,352
Total intrinsic value of options exercised during the period	35,425		212,627

Restricted Stock

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

			Weighted-
	Number of		average Grant-
	Shares		date Fair Value
Unvested at December 31, 2006	41,693		$	26.89
Granted	17,161		47.89
Vested	(7,197	)	20.51
Forfeited	(626	)	39.31
Unvested at March 31, 2007	51,031		34.70

	Three months ended March 31,
	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 first quarter of 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
Unvested at December 31, 2006	125,200		$	24.14
Granted	47,216		31.47
Vested	(40,376	)	23.52
Forfeited	(1,098	)	29.87
Unvested at March 31, 2007	130,942		26.93

	Three months ended March 31,
	2007		2006
Weighted-average grant-date fair value of restricted units granted during the period	$	1,486,074	$	1,412,933

Total fair value of restricted units vested during the period and total intrinsic value of restricted units settled during the period	1,261,750		450,373

During the quarters ended March 31, 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 quarters ended March 31, 2007 and 2006, the Partnership issued 40,376 and 19,286 common units, respectively.

10. Dividends Paid to Shareholders

Cash Dividends

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

On January 26, 2007, the Company’s Board of Directors declared a quarterly cash dividend of $0.30 per share, payable 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.

11. Commitments and Contingencies

Legal

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 their 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 an 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 respond 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 dates predate 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 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 expenses related to the pipeline incident. These expenses include the 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; the 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. 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 expenses and costs 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. In addition to the above, MarkWest has also asserted that a portion of the cost of pipeline testing, replacement and repair is subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.

The Partnership had previously disclosed receiving notice from one of its customers of a potential gas measurement and accounting discrepancy. The Partnership and its customer have been in ongoing discussions evaluate and resolve all issues, and in April 2007, the parties reach final settlement of all outstanding or potential issues to both parties’ satisfaction for an amount of immaterial impact to the Partnership.

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 of 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.

12. 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.

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 months ended March 31, 2007 and 2006 (in thousands):

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Three months ended March 31, 2007:
Revenue:
Revenue	$	72,926		$	121,546		$	(19,075	)	$	175,397
Derivative loss	(6,980		)	(6,929		)	—			(13,909		)
Total revenue	65,946			114,617			(19,075		)	161,488

Purchased product costs	52,814			64,005			(12,612		)	104,207
Facility expenses	5,569			12,956			(6,463		)	12,062
Selling, general and administrative expenses	6,873			13,842			—			20,715
Depreciation	388			7,786			—			8,174
Amortization of intangible assets	—			4,168			—			4,168
Accretion of asset retirement and lease obligations	—			27			—			27
Income from operations	302			11,833			—			12,135

Other income (expense):
Earnings from unconsolidated affiliates	—			1,767			—			1,767
Interest income	476			1,920			—			2,396
Interest expense	(59		)	(9,355		)	—			(9,414		)
Amortization of deferred financing costs (a component of interest expense)	(59		)	(661		)	—			(720		)
Dividend income	122			—			—			122
Miscellaneous expense	(143		)	(729		)	—			(872		)
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	639			4,775			—			5,414
Income tax expense	(494		)	(19		)	16			(497		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(3,960		)	(3,960		)
Interest in net income of consolidated subsidiary	812			—			(812		)	—
Net income	$	957		$	4,756		$	(4,756	)	$	957

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Three months ended March 31, 2006:
Revenue:
Revenue	$	102,092		$	156,742		$	(17,715	)	$	241,119
Derivative (loss) gain	(1,499		)	240			—			(1,259		)
Total revenue	100,593			156,982			(17,715		)	239,860

Purchased product costs	92,322			100,961			(11,655		)	181,628
Facility expenses	5,473			14,069			(6,060		)	13,482
Selling, general and administrative expenses	3,038			8,338			—			11,376
Depreciation	205			7,173			—			7,378
Amortization of intangible assets	—			4,016			—			4,016
Accretion of asset retirement and lease obligations	—			25			—			25
(Loss) income from operations	(445		)	22,400			—			21,955

Other income (expense):
Earnings from unconsolidated affiliates	—			945			—			945
Interest income	186			220			—			406
Interest expense	(68		)	(10,976		)	—			(11,044		)
Amortization of deferred financing costs (a component of interest expense)	(17		)	(808		)	—			(825		)
Dividend income	106			—			—			106
Miscellaneous income	150			2,092			—			2,242
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	(88		)	13,873			—			13,785
Income tax expense	(409		)	—			—			(409		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(10,544		)	(10,544		)
Interest in net income of consolidated subsidiary	3,329			—			(3,329		)	—
Net income	$	2,832		$	13,873		$	(13,873	)	$	2,832

13. Subsequent Event

MarkWest Energy Partners

Private Offering

On April 9, 2007 the Partnership completed a private placement of approximately 4.1 million newly issued common units at a purchase price of $32.98, for net proceeds of approximately $137.6 million, including the General Partner’s contribution to maintain its two percent general partner interest. The proceeds of this transaction will be used primarily to fund capital expenditure requirements.

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;

· he 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 and 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 March 31, 2007, the Company owned a 17% interest in the Partnership, consisting of the following:

· 3,738,992 common units and 1,200,000 subordinated units, representing a 15% 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 (“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 months ended March 31, 2007 and 2006 (in thousands):

	Three months ended March 31,
	2007		2006

Revenue	$	161,488	$	239,860
Purchased product costs	104,207		181,628
Net operating margin	57,281		58,232

Facility expenses	12,062		13,482
Selling, general and administrative expenses	20,715		11,376
Depreciation	8,174		7,378
Amortization of intangible assets	4,168		4,016
Accretion of asset retirement obligations	27		25
Income from operations	$	12,135	$	21,955

Our Business

MarkWest Hydrocarbon Standalone

Our marketing group markets NGL production in Appalachia. In the first quarter of 2007, we sold approximately 62.5 million gallons of NGLs extracted at the Partnership’s Siloam facility. This includes approximately 11.4 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 March 31, 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 14% 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 three months ended March 31, 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)		Total
Revenue	20	%	26	%	35	%	19	%	100	%
Net operating margin	40	%	34	%	14	%	12	%	100	%

(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 is business by taking into account the offset described above, required levels of operational flexibility and the fact that our hedge plan is implemented on this basis. When considered on this basis, the calculated percentages for the net operating margin in the table above for percent-of-proceeds, percent-of-index and keep-whole contracts change to 60%, 0% and 0%, 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 three months ended March 31, 2007, we accounted for 17% of the Partnership’s revenues and 14% of its net operating margin, compared to 11% of revenues and 14% of net operating margin for the three months ending March 31, 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 $0.51 per unit for the quarter ended March 31, 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 $2.5 million for the quarter ended March, 31 2007; our distributions pursuant to our 2% general partner interest have increased from less than $0.1 million to approximately $0.4 million; and our distributions pursuant to our incentive distribution rights have increased from zero to $5.1 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 $8.0 million for the quarter ended March 31, 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 $0.32 per share for the quarter ended March 31, 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, TX	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 March 31, 2007, MarkWest Hydrocarbon Standalone reported operating income of $0.3 million, compared to an operating loss of $0.4 million for the comparable quarter of 2006. MarkWest Hydrocarbon Standalone also reported net income of $1.0 million for the three months ended March 31, 2007, compared to a net income of $2.8 million for the comparable quarter of 2006.

Cash Dividends

We declared a dividend of $0.32 per share on April 20, 2007 for the quarter ended March 31, 2007. The dividend declared is an increase of $0.02, or 6.7%, per share over the 2006 fourth quarter dividend and an increase of $0.15, or 82.9%, per share over the comparable period in 2006.

MarkWest Energy Partners Results

For the three months ended March 31, 2007, the Partnership reported operating income of $11.8 million compared to $22.4 million for the corresponding quarter of 2006, a decrease of $10.6 million, or 47%. The Partnership also reported net income of $4.8 million in the first quarter of 2007, compared to $13.9 million in 2006.

Operating Data

	Three months ended March 31,		%
	2007	2006	Change
MarkWest Hydrocarbon Standalone:
Marketing
Hydrocarbon frac spread sales (gallons)	51,075,000	39,485,000	29.4	%
Maytown sales (gallons)	11,409,000	10,482,000	8.8	%
Total NGL product sales (gallons)(1)	62,484,000	49,967,000	25.1	%

Wholesale
NGL product sales (gallons)(2)	NA	27,196,000	NA

MarkWest Energy Partners:
East Texas:
Gathering systems throughput (Mcf/d)	401,400	346,000	16.0	%
NGL product sales (gallons)	41,788,000	35,436,000	17.9	%

Oklahoma :
Foss Lake gathering systems throughput (Mcf/d)	95,200	87,600	8.7	%
Woodford gathering systems throughput (Mcf/d) (3)	51,200	NA	NA
Grimes gathering systems throughput (Mcf/d) (4)	12,700	NA	NA
Arapaho NGL product sales (gallons)	20,524,000	18,417,000	11.4	%

Other Southwest:
Appleby gathering systems throughput (Mcf/d)	51,100	33,500	52.5	%
Other gathering systems throughput (Mcf/d)	16,400	19,100	(14.1	)%
Lateral throughput volumes (Mcf/d)	52,800	49,700	6.2	%

Appalachia:
Natural gas processed (Mcf/d)	203,400	205,000	(0.8	)%
NGLs fractionated (Gal/d)	467,700	449,000	4.2	%
NGL product sales (gallons)	11,409,000	10,482,000	8.8	%

Michigan:
Natural gas throughput (Mcf/d)	6,000	6,300	(4.8	)%
NGL product sales (gallons)	1,125,000	1,449,000	(22.4	)%
Crude oil transported (Bbl/d)	14,200	14,000	1.4	%

Gulf Coast:
Refinery off-gas processed (Mcf/d)	119,300	120,000	(0.6	)%
Liquids fractionated (Bbl/d)	25,000	24,900	0.4	%

(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 March 31, 2007, compared to the three months ended March 31, 2006

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Three months ended March 31, 2007:
Revenue:
Revenue	$	72,926		$	121,546		$	(19,075	)	$	175,397
Derivative loss	(6,980		)	(6,929		)	—			(13,909		)
Total revenue	65,946			114,617			(19,075		)	161,488

Purchased product costs	52,814			64,005			(12,612		)	104,207
Net operating margin	13,132			50,612			(6,463		)	57,281

Operating expenses:
Facility expenses	5,569			12,956			(6,463		)	12,062
Selling, general and administrative expenses	6,873			13,842			—			20,715
Depreciation	388			7,786			—			8,174
Amortization of intangible assets	—			4,168			—			4,168
Accretion of asset retirement and lease obligations	—			27			—			27
Income from operations	302			11,833			—			12,135

Other income (expense):
Earnings from unconsolidated affiliates	—			1,767			—			1,767
Interest income	476			1,920			—			2,396
Interest expense	(59		)	(9,355		)	—			(9,414		)
Amortization of deferred financing costs (a component of interest expense)	(59		)	(661		)	—			(720		)
Dividend income	122			—			—			122
Miscellaneous expense	(143		)	(729		)	—			(872		)
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	639			4,775			—			5,414
Income tax expense	(494		)	(19		)	16			(497		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(3,960		)	(3,960		)
Interest in net income of consolidated subsidiary	812			—			(812		)	—
Net income	$	957		$	4,756		$	(4,756	)	$	957

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Three months ended March 31, 2006:
Revenue:
Revenue	$	102,092		$	156,742		$	(17,715	)	$	241,119
Derivative (loss) gain	(1,499		)	240			—			(1,259		)
Total revenue	100,593			156,982			(17,715		)	239,860

Purchased product costs	92,322			100,961			(11,655		)	181,628
Net operating margin	8,271			56,021			(6,060		)	58,232

Operating expenses:
Facility expenses	5,473			14,069			(6,060		)	13,482
Selling, general and administrative expenses	3,038			8,338			—			11,376
Depreciation	205			7,173			—			7,378
Amortization of intangible assets	—			4,016			—			4,016
Accretion of asset retirement and lease obligations	—			25			—			25
(Loss) income from operations	(445		)	22,400			—			21,955

Other income (expense):
Earnings from unconsolidated affiliates	—			945			—			945
Interest income	186			220			—			406
Interest expense	(68		)	(10,976		)	—			(11,044		)
Amortization of deferred financing costs (a component of interest expense)	(17		)	(808		)	—			(825		)
Dividend income	106			—			—			106
Miscellaneous income	150			2,092			—			2,242
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	(88		)	13,873			—			13,785
Income tax expense	(409		)	—			—			(409		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(10,544		)	(10,544		)
Interest in net income of consolidated subsidiary	3,329			—			(3,329		)	—
Net income	$	2,832		$	13,873		$	(13,873	)	$	2,832

MarkWest Hydrocarbon Standalone

Revenue. Revenue decreased $29.2 million, or 29%, for the quarter ended March 31, 2007, compared to the corresponding period in 2006. We realized an $11.1 million decrease in our gas marketing business due primarily to lower prices and volumes of $0.96/MMBtu and 12,200 MMBtu/d, respectively. The $27.3 million decrease in revenues in our wholesale business are attributable to the expiration of a marketing arrangement. Additionally, the revaluation of our long-term shrink obligation decreased revenue by $1.9 million in the three months ended March 31, 2007, compared to a $4.2 million increase for the same period in 2006, resulting in an $6.1 million decrease for the period-over-period comparison. These decreases were partially offset by an increase in our frac spread NGL revenues of $15.3 million, an increase primarily the result of decreases in prices ($0.09/Gal), offset slightly by a decrease in volumes (129,000/Gal/d).

Derivative (Loss) Gain. Losses from derivative instruments increased $5.5 million during the quarter ended March 31, 2007 compared to the corresponding period in 2006. This loss was primarily due to the mark-to-market adjustments resulting from our election not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $7.9 million increase in unrealized losses, which are non-cash items, and a $2.4 million increase in realized losses, when comparing the first quarter of 2007 to 2006 results.

Purchased Product Costs. Purchased product costs decreased $39.5 million, or 43%, for the quarter ended March 31, 2007, compared to the corresponding period in 2006. The decrease was primarily due to our natural gas marketing business which reflected a decrease of $10.3 million. This was primarily due to a decrease in prices and volumes. A $27.3 million decrease in purchased product costs in our wholesale business is attributable to the expiration of a marketing arrangement. Additionally, we recorded a decrease in our frac spread purchase product costs of $0.3 million, resulting primarily from decreased prices. Finally, the value of a certain contract is marked-to-market based on an index price through purchased product costs. The mark-to-market adjustments resulted in a $2.0 million increase in unrealized losses, which are non-cash items, and $0.4 million increase in realized gains.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $3.8 million, or 126%, during the three months ended March 31, 2007, compared to the corresponding period in 2006. This increase was primarily due to a $2.4 million non-cash increase to the participation plan compensation expense as a result of the Partnership’s increased market value. Personnel costs increased $0.5 million due to the cost of additional personnel necessary to support our growth. Additionally, we experienced an increase in professional service costs of $0.5 million.

MarkWest Energy Partners

Revenue. Revenue decreased $35.2 million, or 22%, for the three months ended March 31, 2007, compared to the corresponding period of 2006, mostly due to the conversion of contracts. East Texas contributed $10.4 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. Oklahoma made up $15.3 million of the decrease primarily related to the conversion of several purchase contracts to gathering contracts. Additionally, Other Southwest experienced a decline in revenue of $10.1 primarily attributed to a change in the contract mix at it Appleby facility, from purchasing contracts to gathering contracts, which occurred in the third quarter of 2006.

Derivative (Loss) Gain). Loss from derivative instruments increased $6.7 million, during the three months ended March 31, 2007, compared to the corresponding period in 2006. The mark-to-market adjustments of the Partnership’s derivative instruments resulted in a $2.3 million increase in realized gains, and a $9.0 million increase in unrealized losses, when comparing 2007 to 2006 results.

Purchased product costs. Purchased product costs decreased $37.0 million, or 37%, for the three months ended March 31, 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 decreased $1.1 million, or 8%, during the three months ended March 31, 2007, compared to the corresponding period in 2006. This decrease is primarily attributable to a utility refund of $3.6 million attributable to a recently concluded rate case in the Gulf Coast Business Unit; and the decrease is offset by an increase in the East Texas Business Unit of $0.6 million due to higher volumes and an increase of $1.5 million related to the addition of the Woodford and Grimes gathering systems in the Partnership’s Oklahoma segment.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $5.5 million, or 66%, during the three months ended March 31, 2007, relative to the comparable period in 2006. $4.2 million of the increase can be attributed to higher non-cash equity-based compensation expense. Of this amount, $3.7 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 to the increase in equity-based compensation expense, labor and professional services costs increased.

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 LLC. 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 March 31, 2007, our earnings from unconsolidated affiliates increased $0.8 million, or 87%, 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 Income. Interest income increased $1.7 million, during the three months ended March 31, 2007, relative to the comparable period in 2006 due to proceeds received from the settlement of a rate case in the Partnership’s Gulf Coast Business Unit.

Interest Expense. Interest expense decreased $1.6 million, or 15%, during the three months ended March 31, 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 and lower weighted average interest rates on the Partnership’s long-term debt.

Miscellaneous (Expense) Income. Miscellaneous expense increased $2.8 million, or 135%, during the three months ended March 31, 2007, relative to the comparable period in 2006, primarily due to $1.8 million of income from insurance recoveries in 2006. An additional $0.9 million increase was due to Starfish insurance premiums paid during the three months ended March 31, 2007.

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 quarter ended March 31, 2007, we received $2.5 million in distributions from our limited units and $4.6 million from our general partner interest, of which $4.2 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 March 31, 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 three months ended March 31, 2007 the weighted average interest rate on the Credit Facility was 7.59%.

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, for the three months ended March 31, 2007, available borrowings under the Credit Facility were $168.4 million. Following the closing of the Partnership’s private placement on April 9, 2007 (see Note 13 to the condensed consolidated financial statements), the Partnership’s available borrowings on its Credit Facility were $248.4 million.

Senior Notes

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 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 budgeted approximately $260 million for expenditures in 2007, which includes $5 million for maintenance capital. The Partnership plans to use from $180 to $200 million of its expansion capital budget to fund the construction of the Woodford gathering system. As of March 31, 2007, the Partnership has $186 million remaining in its budget including $4.3 million for maintenance capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets, or facilitate an increase in volumes within our operations, whether through construction or acquisition. Maintenance capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

Cash Flows

The following table summarizes cash inflows (outflows) for the three months ended March 31, 2007 and 2006 (in thousands):

	Three months ended March 31,
	2007			2006
Net cash provided by operating activities	$	56,600		$	55,624
Net cash used in investing activities	(55,033		)	(13,970		)
Net cash provided by (used in) financing activities	32,418			(23,990		)

Net cash provided by operating activities increased $1.0 million during the three months ended March 31, 2007, compared to the corresponding period in 2006. The change resulted from an increase in cash flows provided by income before non-cash income and expenses of $14.7 million, offset by a decrease in operating cash flows provided by working capital of $13.7 million. The change in income before non-cash income and expense was primarily a result of a $5.5 million refund from the Partnership’s recently concluded rate case, a $4.3 million increase in realized gains from derivative instruments and a $2.7 million distribution received from an equity investment. 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 decreased by $41.1 million during the quarter ended March 31, 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 $40.9 million of expansion capital.

Net cash used in financing activities increased $56.4 million during the during quarter ended March 31, 2007, compared to the same period in 2006 primarily to net increase of $69.0 of borrowings under the Partnerships Credit Facility. Distributions to the Partnership’s unitholders increased to $13.7 million in the first quarter of 2007 from $8.5 million in the first quarter of 2006. Dividends to shareholders increased to $3.6 million during the quarter ended March 31, 2007 compared to $1.4 million in the comparable period in 2006.

Matters Influencing 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 the Partnership’s unconsolidated affiliate, Starfish Pipeline Company were nominally impacted by Hurricane Katrina but were significantly impacted by Hurricane Rita. The Partnership is continuing to submit insurance claims on an on-going basis relating to both business interruption and property damage. The Partnership has recorded $8.7 million in insurance claims, net of Starfish insurance premiums with respect to its property loss claims, and it anticipates additional recoveries for expenses and losses incurred as repairs proceed.

The loss to both offshore and onshore assets resulting from Hurricane Rita has led to substantial insurance claims within the oil and gas industry. Along with other industry participants, the Partnership has seen our 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 our 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, and 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 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. In the interim, MEA is trucking the NGLs produced from our 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 8 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 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 the lack of liquidity in the NGL financial market, we have used crude oil derivative instruments to hedge NGL price risk. As a result of these transactions, we have hedged a significant portion of our expected natural gas and NGL commodity price risk through the first quarter of 2010. The margins we earn from condensate sales are directly correlated with crude oil prices.

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.

MarkWest Hydrocarbon Standalone

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

The following tables summarizes the current derivative positions specific to the MarkWest Hydrocarbon Standalone segment at March 31, 2007:

Fixed Physical Forward	Contract Period	Price (2)		Fair Value
				(in thousands)

Natural Gas - 6,308 MMBtu/d (sale)	Apr 2007	$	7.48	$	(91	)
Natural Gas - 28,091 MMBtu/d (sale)	May 2007	6.72		(1,203		)
Natural Gas - 4,665 MMBtu/d (sale)	Jun 2007	7.48		(100		)

Fixed Swaps (1)	Contract Period	Price (2)		Fair Value
				(in thousands)
Crude - 277 Bbl/d (sale)	Apr 2007	$	64.37	$	(17	)
Crude - 642 Bbl/d (sale)	Apr-Jun 2007	67.00		(30		)
Crude - 313 Bbl/d (sale)	Apr-Jun 2007	80.21		358
Crude - 36 Bbl/d (sale)	May 2007	64.62		(3		)
Crude - 241 Bbl/d (sale)	Jun 2007	65.32		(22		)
Crude - 1,323 Bbl/d (sale)	Jul 2007	65.68		(130		)
Crude - 1,396 Bbl/d (sale)	Aug 2007	65.99		(136		)
Crude - 1,547 Bbl/d (sale)	Sep 2007	66.26		(144		)
Crude - 2,504 Bbl/d (sale)	Oct 2007	66.48		(238		)
Crude - 2,766 Bbl/d (sale)	Nov 2007	66.70		(248		)
Crude - 3,916 Bbl/d (sale)	Dec 2007	66.91		(347		)
Crude - 4,361 Bbl/d (sale)	Jan 2008	67.04		(377		)
Crude - 3,913 Bbl/d (sale)	Feb 2008	67.14		(310		)
Crude - 2,320 Bbl/d (sale)	Mar 2008	67.23		(193		)

Natural Gas - 7,088 MMBtu/d (purchase)	Apr 2007	8.16		(59		)
Natural Gas - 86,850 MMBtu/d (purchase)	May 2007	8.08		(108		)
Natural Gas - 13,167 MMBtu/d (purchase)	Jun 2007	8.16		(13		)
Natural Gas - 12,581 MMBtu/d (purchase)	Jul 2007	8.29		(21		)
Natural Gas - 12,258 MMBtu/d (purchase)	Aug 2007	8.35		(7		)
Natural Gas - 4,833 MMBtu/d (purchase)	Sep 2007	8.38		(2		)

(1) Forward sales to hedge our production.

(2) A weighted average price is used for grouped positions.

We have also entered into a contract with one of the largest producers in the Appalachia region which creates a floor on the frac spread that can be realized on a specified volume purchased. Under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS 133”) the value of this contract is marked based on an index price through purchased product costs. As of March 31, 2007, the value of this contract was marked as a current liability of $1.8 million.

The following tables summarizes the non-current derivative positions specific to the MarkWest Hydrocarbon Standalone segment at March 31, 2007:

Fixed Swaps (1)	Contract Period	Price (2)		Fair Value
				(in thousands)
Crude - 921 Bbl/d (sale)	Apr 2008	$	64.22	$	(155	)
Crude - 1,087 Bbl/d (sale)	May 2008	63.95		(196		)
Crude - 1,096 Bbl/d (sale)	Jun 2008	63.93		(191		)
Crude - 1,025 Bbl/d (sale)	Jul 2008	64.08		(178		)
Crude - 1,124 Bbl/d (sale)	Aug 2008	64.22		(188		)
Crude - 1,268 Bbl/d (sale)	Sep 2008	64.53		(192		)
Crude - 2,517 Bbl/d (sale)	Oct 2008	65.37		(329		)
Crude - 3,479 Bbl/d (sale)	Nov 2008	65.52		(417		)
Crude - 3,856 Bbl/d (sale)	Dec 2008	65.51		(462		)
Crude - 4,721 Bbl/d (sale)	Jan 2009	65.52		(548		)
Crude - 4,212 Bbl/d (sale)	Feb 2009	65.45		(438		)
Crude - 3,069 Bbl/d (sale)	Mar 2009	65.33		(351		)
Crude - 921 Bbl/d (sale)	Apr 2009	63.92		(133		)
Crude - 1,087 Bbl/d (sale)	May 2009	63.62		(166		)
Crude - 1,096 Bbl/d (sale)	Jun 2009	63.68		(156		)
Crude - 1,026 Bbl/d (sale)	Jul 2009	63.71		(144		)
Crude - 1,195 Bbl/d (sale)	Aug 2009	64.01		(152		)
Crude - 1,306 Bbl/d (sale)	Sep 2009	64.18		(150		)
Crude - 2,378 Bbl/d (sale)	Oct 2009	64.69		(237		)
Crude - 3,556 Bbl/d (sale)	Nov 2009	64.79		(322		)
Crude - 3,792 Bbl/d (sale)	Dec 2009	64.70		(349		)
Crude - 4,729 Bbl/d (sale)	Jan 2010	64.59		(431		)
Crude - 4,218 Bbl/d (sale)	Feb 2010	64.55		(341		)
Crude - 3,073 Bbl/d (sale)	Mar 2010	64.55		(262		)
Natural Gas - 4,070 MMBtu/d (purchase)	Apr 2008	8.05		35
Natural Gas - 15,873 MMBtu/d (purchase)	Apr-Jun 2008	8.01		365
Natural Gas - 5,361 MMBtu/d (purchase)	May 2008	7.93		45
Natural Gas - 5,482 MMBtu/d (purchase)	Jun 2008	7.98		46
Natural Gas - 15,755 MMBtu/d (purchase)	Jul 2008	8.05		123
Natural Gas - 15,701 MMBtu/d (purchase)	Jul-Sep 2008	8.10		389
Natural Gas - 15,755 MMBtu/d (purchase)	Aug 2008	8.11		127
Natural Gas - 16,280 MMBtu/d (purchase)	Sep 2008	8.16		130
Natural Gas - 4,070 MMBtu/d (purchase)	Apr 2009	7.64		38
Natural Gas - 15,883 MMBtu/d (purchase)	Apr-Jun 2009	7.61		399
Natural Gas - 5,361 MMBtu/d (purchase)	May 2009	7.51		52
Natural Gas - 5,482 MMBtu/d (purchase)	Jun 2009	7.56		53
Natural Gas - 15,755 MMBtu/d (purchase)	Jul 2009	7.60		155
Natural Gas - 15,710 MMBtu/d (purchase)	Jul-Sep 2009	7.73		369
Natural Gas - 15,755 MMBtu/d (purchase)	Aug 2009	7.69		141
Natural Gas - 16,280 MMBtu/d (purchase)	Sep 2009	7.78		125

(1) Forward sales to hedge our production.

(2) A weighted average price is used for grouped positions.

The impact of MarkWest Hydrocarbon Standalone’s commodity derivative instruments on results of operations and financial position is summarized below (in thousands):

	March 31, 2007		December 31, 2006
Fair value of derivative instruments:
Current asset	$	358	$	5,727
Non-current asset	2,592		35
Current liability	5,568		7,385
Non-current liability	6,488		98

The Company had not entered into any additional derivative positions subsequent to March 31, 2007, and prior to the date of this report.

MarkWest Energy Partners

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 we largely expect our realized derivative gains and losses to be offset by increases or decreases in the value of our physical sales, we will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative positions that will have no offset. The volatility in any given period related to unrealized gains or losses can be significant to the overall financial results of the Partnership; however, we ultimately expect those gains and losses to be offset when they become realized.

The following tables summarize the Partnership’s current derivative positions at March 31, 2007:

Fixed Swaps (1)	Contract Period	Fixed Price (2)		Fair Value
				(in thousands)
Crude - 1,325 Bbl/d	Apr-Dec 2007	$	63.95	$	(1,736	)
Crude - 140 Bbl/d	Apr-Dec 2007	74.10		199

Basis Swaps	Contract Period	Fair Value
		(in thousands)
Natural Gas - 14,000 MMBtu/d	Apr-Oct 2007	$	(59	)

Options (puts) (3)	Contract Period	Floor		Fair Value
				(in thousands)
Ethane - 50,000 Gal/d	Apr-Dec 2007	$	0.65	$	(352	)

Collars (4)	Contract Period	Floor (2)		Cap (2)		Fair Value
						(in thousands)
Crude - 1,105 Bbl/d	Apr-Dec 2007	$	69.08	$	82.43	$	1,015
Crude - 1,476 Bbl/d	Jan-Mar 2008	69.76		79.01		413
Crude - 1,475 Bbl/d	Jan-Mar 2008	64.80		70.71		(261		)

Propane - 30,000 Gal/d	Apr-Jun 2007	0.96		1.16		(41		)
Propane - 30,000 Gal/d	Jul-Sep 2007	0.97		1.16		(85		)
Propane - 30,000 Gal/d	Oct-Dec 2007	0.98		1.18		—

(1) Forward sales to hedge our production.

(2) A weighted average price is used for grouped positions.

(3) Purchase of puts to hedge our Ethane production.

(4) Forward producer collars to hedge our production.

The Partnership has also entered into a contract which gives it an option to fix a component of the price of electricity at one of its plant locations. Under SFAS 133, the value of this contract is marked based on an index price through facilities expense. As of March 31, 2007, the value of this contract was marked as a long-term asset of $0.7 million and a short-term liability of $0.3 million.

The following tables summarize the Partnership’s non-current derivative positions at March 31, 2007:

Fixed Swaps (1)	Contract Period	Fixed Price (2)		Fair Value
				(in thousands)
Crude - 85 Bbl/d	Jan 2010	$	66.35	$	(4	)
Crude - 2,866 Bbl/d	Jan-Mar 2010	64.54		(744		)
Crude - 79 Bbl/d	Feb 2010	66.35		(3		)
Crude - 75 Bbl/d	Mar 2010	66.35		(3		)
Crude - 1,199 Bbl/d	Apr 2010	66.27		(42		)
Crude - 1,202 Bbl/d	May 2010	66.27		(40		)
Crude - 1,153 Bbl/d	Jun 2010	66.28		(32		)

Collars (3)	Contract Period	Floor (2)		Cap (2)		Fair Value
						(in thousands)
Crude - 1,473 Bbl/d	Apr-Jun 2008	$	69.48	$	78.66	$	375
Crude - 1,475 Bbl/d	Apr-Dec 2008	64.80		70.71		(790		)
Crude - 1,437 Bbl/d	Jul-Sep 2008	68.90		78.32		329
Crude - 1,473 Bbl/d	Oct-Dec 2008	68.41		77.85		304
Crude - 2,475 Bbl/d	Jan-Dec 2009	63.78		69.72		(2,096		)
Crude - 450 Bbl/d	Jan-Dec 2009	63.00		70.00		(586		)

(1) Forward sales to hedge production.

(2) A weighted average price is used for grouped positions.

(3) Forward producer collars to hedge production.

The impact of the Partnership’s commodity derivative instruments on results of operations and financial position are summarized below (in thousands):

	March 31, 2007		December 31, 2006
Fair value of derivative instruments:
Current asset	$	1,627	$	4,211
Non-current asset	1,739		2,759
Current liability	2,832		91
Non-current liability	4,340		1,362

The Partnership entered into the following derivative positions subsequent to March 31, 2007:

Fixed Swaps	Contract Period	Fixed Price (1)
Crude - 875 Bbl/d(2)	Jun-Sep 2007	$	66.55
Crude - 483 Bbl/d(2)	Jun-Dec 2007	69.25
Crude - 150 Bbl/d(3)	Jan-Dec 2008	69.76

Natural Gasoline - 9,724 Gal/d(3)	Jun-Sep 2007	1.60
Natural Gasoline - 3,780 Gal/d(3)	Jun-Dec 2007	1.61

Propane - 27,322 Gal/d(3)	Jun-Sep 2007	1.13
Propane - 15,461 Gal/d(3)	Jun-Dec 2007	1.14

Normal Butane - 6,554 Gal/d(3)	Jun-Sep 2007	1.28
Normal Butane - 4,459 Gal/d(3)	Jun-Dec 2007	1.31

Isobutane - 5,282 Gal/d(3)	Jun-Sep 2007	1.39
Isobutane - 3,997 Gal/d(3)	Jun-Dec 2007	1.37

Collars (4)	Contract Period	Floor (1)		Cap (1)
Crude - 595 Bbl/d	Apr 2010	$	66.00	$	72.00
Crude - 597 Bbl/d	May 2010	66.00		72.00
Crude - 573 Bbl/d	Jun 2010	66.00		72.00

(1) A weighted average price is used for grouped positions.

(2) Forward purchases to modify existing hedge positions.

(3) Forward sales to hedge production.

(4) Forward producer collars to hedge production.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2007 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to allow disclosure as required in this report.

Changes in Internal Control Over Financial Reporting

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, to determine whether any changes occurred during the first quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management has adopted remedial measures to address the material weakness in our internal controls that existed on December 31, 2006. The remediation procedures included detailed management review of substantially all contracts in effect at December 31, 2006, for the presence of derivatives or embedded derivatives. In addition, we enhanced the procedures

around contract reviews and monitoring of new accounting guidance, including the development of a newly designed contract review and approval process. Based on these procedures, management has concluded that the material weakness that existed at December 31, 2006, has been remediated.

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

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

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

10.1(1)		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(2)		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 Hydrocarbon’s Current Report on Form 8-K, filed with the Commission on February 23, 2007.

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

	MarkWest Hydrocarbon, Inc.
	(Registrant)

Date: May 7, 2007	/s/ FRANK M. SEMPLE
	Frank M. Semple
	President and Chief Executive Officer
	(Principal Executive Officer)

Date: May 7, 2007	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)

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

Item 1. Legal Proceedings

SIGNATURES