PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited, in thousands)

	March 31, 2006			December 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	38,632		$	20,968
Marketable securities	6,378			6,070
Receivables, net of allowance for doubtful accounts of $164 and $175, respectively	102,163			145,539
Inventories	16,056			30,500
Prepaid replacement natural gas	4,377			10,567
Other current assets	21,920			16,314
Total current assets	189,526			229,958

Property, plant and equipment	586,469			573,198
Less: accumulated depreciation, depletion, amortization and impairment	(85,534		)	(78,500		)
Total property, plant and equipment, net	500,935			494,698

Other assets:
Investment in Starfish	40,986			39,167
Intangible assets, net	342,839			346,496
Deferred financing costs, net of accumulated amortization of $5,263 and $4,442, respectively	17,730			18,463
Deferred contract cost, net of accumulated amortization of $468 and $390, respectively	2,782			2,860
Investment in and advances to other equity investee	199			182
Other long term assets	326			326
Notes receivable from related parties	154			154
Total other assets	405,016			407,648
Total assets	$	1,095,477		$	1,132,304

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable (including related party payables of $0 and $25, respectively)	$	96,674		$	119,105
Accrued liabilities	41,677			45,869
Fair value of derivative instruments	2,526			728
Deferred income taxes	477			362
Current portion of long term debt	3,650			2,738
Total current liabilities	145,004			168,802

Deferred income taxes	4,390			3,487
Long-term debt	588,850			608,762
Other long-term liabilities	11,937			10,256
Non-controlling interest in consolidated subsidiary	303,480			301,015
Total liabilities	1,053,661			1,092,322

Commitments and contingencies (Note 10)

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, 10,862,573 and 10,857,939 shares issued, respectively	109			108
Additional paid-in capital	46,906			48,797
Deferred compensation	—			(398		)

Accumulated deficit	(5,593		)	(8,425		)
Accumulated other comprehensive income, net of tax	550			357
Treasury stock, 16,118 and 55,619 shares, respectively	(156		)	(457		)
Total stockholders’ equity	41,816			39,982
Total liabilities and stockholders’ equity	$	1,095,477		$	1,132,304

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share amounts)

	Three Months Ended March 31,
	2006			2005

Revenues:
Revenue	$	240,880		$	138,260
Derivatives	(1,259		)	93
Total revenues	239,621			138,353

Operating expenses:
Purchased product costs	181,167			104,699
Facility expenses	13,704			9,260
Selling, general and administrative expenses	11,376			8,102
Depreciation	7,378			4,741
Amortization of intangible assets	4,016			2,095
Accretion of asset retirement obligations	25			10
Total operating expenses	217,666			128,907

Income from operations	21,955			9,446

Other income (expense):
Earnings from unconsolidated subsidiary	945			—
Interest income	406			249
Interest expense	(11,044		)	(3,704		)
Amortization of deferred financing costs (a component of interest expense)	(825		)	(536		)
Dividend income	106			92
Other income	2,242			87

Income from operations before non-controlling interest in net income of consolidated subsidiary and income taxes	13,785			5,634

Income tax (expense) benefit
Current	493			—
Deferred	(902		)	(770		)
Income tax expense	(409		)	(770		)

Non-controlling interest in net income of consolidated subsidiary	(10,544		)	(3,325		)
Net income	$	2,832		$	1,539

Net income per share:
Basic	$	0.26		$	0.14
Diluted	$	0.26		$	0.14

Weighted average number of outstanding shares of common stock:
Basic	10,821			10,766
Diluted	10,923			10,917

Cash dividend per common share	$	0.175		$	0.075

The accompanying financial statements are an integral part of these unaudited 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			Deferred Compensation			Accumulated Earnings (Deficit)			Accumulated Other Comprehensive Income		Treasury Stock			Total

Balance, December 31, 2005	10,858	(56	)	$	108	$	48,797		$	(398	)	$	(8,425	)	$	357	$	(457	)	$	39,982
Stock option exercises	—	5		1		(1		)	—			—			—		43			43
Stock-based compensation	—	—		—		121			—			—			—		—			121
Issuance of restricted stock	1	35		—		(258		)	—			—			—		258			—
Cashless stock options	4	—		—		—			—			—			—		—			—
Reclassification of unearned compensation related to the adoption of Statement of Financial Accounting Standards No. 123(R) (Note 2)	—	—		—		(398		)	398			—			—		—			—
Net income	—	—		—		—			—			2,832			—		—			2,832
Dividend	—	—		—		(1,355		)	—			—			—		—			(1,355		)
Other comprehensive income	—	—		—		—			—			—			193		—			193
Balance, March 31, 2006	10,863	(16	)	$	109	$	46,906		$	—		$	(5,593	)	$	550	$	(156	)	$	41,816

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	March 31,
	2006			2005

Cash flows from operating activities:
Net Income	$	2,832		$	1,539
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	7,378			4,741
Amortization of intangible assets	4,016			2,095
Amortization of deferred financing costs	825			536
Amortization of gas contract	78			78
Accretion of asset retirement obligation	25			10
Non-controlling interest in net income of consolidated subsidiary	10,544			3,325
Equity in earnings of investee	(945		)	(3		)
Unrealized losses (gains) on derivative instruments	1,798			(766		)
Deferred income taxes	902			770
Stock option compensation expense	21			720
Restricted stock compensation expense	105			14
Restricted unit compensation expense	458			230
Participation Plan compensation expense	1,496			1,607
Contribution of treasury shares to 401(k) benefit plan	43			105
Gain from sale of property, plant and equipment	(410		)	(39		)
Gain from sale of marketable securities	—			(60		)

Changes in operating assets and liabilities, net of working capital acquired in acquisitions:
Decrease in receivables	38,376			19,710
Decrease in inventories	14,444			3,956
Decrease in prepaid replacement natural gas and other assets	6,190			6,187
Decrease (increase) in other current assets	(5,606		)	44
Decrease in accounts payable and accrued liabilities	(27,038		)	(5,548		)
Increase in other long-term liabilities	92			225
Net cash provided by operating activities	55,624			39,476

Cash flows from investing activities:
Purchase of marketable securities	—			(7,437		)
Proceeds from sale of marketable securities	—			1,634
Javelina acquisition, net of cash acquired	(360		)	—
Capital expenditures	(13,249		)	(16,000		)
Proceeds from sale of property, plant and equipment	529			39
Investment in equity affiliate	(890		)	(41,688		)
Net cash used in investing activities	(13,970		)	(63,452		)

Cash flows from financing activities:
Proceeds from long-term debt	25,000			40,000
Repayments of long-term debt	(44,000		)	—
Payments for debt issuance costs	(105		)	(50		)
Proceeds from MarkWest Energy’s private placement, net	5,000			—
Distributions to MarkWest Energy unitholders	(8,529		)	(6,375		)
Payment of dividends	(1,355		)	(808		)
Exercise of stock options	(1		)	37
Purchase of treasury shares	—			(161		)
Proceeds from sale of MarkWest Energy units	—			37
Net cash provided by (used in) financing activities	(23,990		)	32,680

Net increase in cash and cash equivalents	17,664			8,704
Cash and cash equivalents at beginning of year	20,968			12,844
Cash and cash equivalents at end of year	$	38,632		$	21,548

Supplemental disclosures of cash flow information:
Cash paid for interest	$	5,319		$	4,147

Supplemental disclosures of non-cash investing and financing activities:
Starfish insurance recovery	$	1,800		—

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

MARKWEST HYDROCARBON, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon” or the “Company”) is an energy company primarily focused on marketing natural gas liquids (NGLs) 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 we exercise significant influence but do not control, and are not the primary beneficiary, are accounted for using the equity method. The Company regularly reviews its investments to determine whether a decline in fair value below the cost basis is other than temporary. The Company’s accounting policy requires it to evaluate operating losses (if any), credit defaults and other factors that may indicate a decrease in value of the investment that is other than temporary. The primary factors the Company considers in its determination of an impairment that is other than temporary are the length of time that the fair value of the investment is below the Company’s carrying value and the financial condition, operating performance and near-term prospects of the investee. The Company also considers the reason for the decline in fair value, be it general market conditions, industry-specific or investee-specific; and the Company’s intent and ability to hold the investment for a period of time sufficient to allow for a recovery in fair value. The Company evaluates fair value based on specific information (valuation methodologies, financial statements, estimates of appraisals, etc.). Due to a lack of a public market price for the Company’s current investments, it uses its best estimates and assumptions to arrive at the estimated fair value of such investments. If the decline in fair value is deemed to be other than temporary, the cost basis of the security is written down to fair value. The Company’s assessment of the foregoing factors involves a high degree of judgment and, accordingly, actual results may differ materially from the Company’s estimates and judgments.

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 annual financial statements prepared in accordance with GAAP have been condensed or omitted. In management’s opinion, we have made all adjustments necessary for a fair presentation of the Company’s 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 notes that makes up the Company’s December 31, 2005, Annual Report on Form 10-K. Finally, consider that results for the three months ended March 31, 2006, are not necessarily indicative of results for the full year 2006, or any other future period.

Stock and Incentive Compensation Plans

The Company adopted SFAS No. 123R, Accounting for Stock-Based Compensation on January 1, 2006, using the modified prospective method. Prior to adopting SFAS No. 123R, the Company elected to measure compensation expense for equity-based employee compensation plans as prescribed by Accounting Principles Board (“APB”) No. 25, Accounting for Stock Issued to Employees.

Under SFAS No. 123R, compensation expense is based on the fair value of the award. SFAS No. 123R classifies stock-based compensation as either equity or liability awards. The fair value on the date of grant for an award classified as equity is recognized over the requisite service period, with a corresponding credit to equity (generally, paid-in capital). The requisite service period is the period during which an individual is required to provide service in exchange for an award, which often is the vesting period. The requisite service period is estimated based on an analysis of the terms of the share-based payment award. Compensation expense for a liability award is based on the award’s fair value, remeasured at each reporting date until the date of settlement. Additionally, compensation expense is reduced by 4.6% for an estimate of expected award forfeitures.

Under APB No. 25, compensation expense is based on the intrinsic value (typically the difference between the equity-based instrument to be received and the cost to acquire that equity-based instrument). APB No. 25 classified stock-

based compensation as either fixed or variable awards. The intrinsic value on the date of grant for an award classified as fixed is recognized over the requisite service period. Compensation expense for variable awards is based on the award’s intrinsic value, remeasured at each reporting date until the date of settlement.

Compensation expense under each plan is included in selling, general and administrative expenses.

MarkWest Hydrocarbon

Stock Options

Stock options are issued under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. Under SFAS No. 123R, the plans are categorized as equity awards. Under APB No. 25, the plans were categorized as variable awards.

Restricted Stock

The Company also issues restricted stock, for no consideration, under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. Upon settlement, the individual receives common stock of the Company. Under SFAS No. 123R, the restricted stock qualifies as an equity award, and under APB No. 25 qualified as a fixed award.

Participation Plan

The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under the Participation Plan, the Company sells subordinated partnership units of the Partnership or interests in the Partnership’s general partner, under a purchase and sale agreement. As the formula used to determine the sale and buy-back price is not based on independent third party valuation, coupled with the attributes of the put-and-call provisions, these transactions are considered compensatory arrangements. The general partner interests may be held indefinitely, but have historically been settled for cash when the employee leaves the Company. The subordinated units convert to common units after a holding period; however, historically, management has settled some subordinated units for cash when individuals have left the Company. The subordinated partnership units of the Partnership were also sold to the employees and directors based on a formula that may not necessarily fully reflect fair value, thus the subordinated units are considered compensatory. Under SFAS 123R, the subordinated units and general partner interests are classified as liability awards, while under APB No. 25, they were classified as variable awards.

Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity, some portion of compensation expense related to services provided by MarkWest Hydrocarbon’s employees and directors recognized under the Participation Plan should be allocated to the Partnership. The allocation is based on the percent of time that each employee devotes to the Company. Compensation attributable to interests that were sold to individuals who serve on both the board of MarkWest Hydrocarbon and the Partnership’s Board of Directors is allocated equally.

MarkWest Energy Partners

Restricted Units

The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units are treated as liability awards under SFAS No. 123R, and were treated as variable awards under APB No. 25.

To satisfy common unit awards, common units may be acquired on the open market, from the general partner or any other person, as well as from the issuance of new common units. The cost of the common unit awards, therefore, will be borne by the Partnership.

Pro Formas

Had compensation cost for the Company’s stock-based and unit-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123R, Accounting for Stock-Based Compensation, the Company’s net income and earnings per share would have been reduced to the pro forma amounts listed below (in thousands, except per share data):

	Three months ended March 31, 2005
Net income, as reported	$	1,539
Add: compensation expense included in reported net income, net of related tax effect	1,712
Deduct: total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect	(1,257		)
Pro forma net income	$	1,994

Net income per share:
Basic:
As reported	$	0.14
Pro forma	$	0.19
Diluted:
As reported	$	0.14
Pro forma	$	0.19

3. Recent Accounting Pronouncements

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 replaces Accounting Principles Board Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. This statement applies to all voluntary changes in accounting principle and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company adopted the provisions of SFAS No. 154 beginning in January 2006. The adoption of the provisions of SFAS No. 154 did not have an impact on the Company’s condensed consolidated financial statements.

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 (“SFAS 155”). This statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and resolves issues addressed in SFAS 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interest in Securitized Financial Assets.” This Statement: (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to evaluate beneficial interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity’s ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. The Company is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of an entity’s fiscal year. The adoption of SFAS 155 is not expected to have a material impact on the condensed consolidated financial statements of the Company.

4. Acquisitions by MarkWest Energy Partners

Javelina Acquisition

On November 1, 2005, the Partnership acquired equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were 40%, 40% and 20%, respectively, owned by subsidiaries of El Paso Corporation, Kerr-McGee Corporation and Valero Energy Corporation. The Partnership paid consideration of $357.0 million, plus $41.3 million for net working capital that included approximately $35.5 million in cash. The Corpus Christi, Texas, gas-processing facility treats and processes off-gas from six local refineries, two of which are owned by Valero Energy Corporation, two by Koch Industries, Inc. and two by Citgo Petroleum Corporation. Constructed in 1989 to recover up to 28,000 Bbl/d of NGLs, the facility currently processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 25,400 Bbl/d of NGLs. The Partnership and the seller are still negotiating the final value of the acquired working capital, so the purchase price may change upon settlement.

Starfish Joint Venture

On March 31, 2005, the Partnership acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC, (“Starfish”) from an affiliate of Enterprise Products Partners L.P. for $41.7 million. The Partnership financed the acquisition by borrowing $40.0 million from its credit facility during the first quarter of 2005. Starfish is a joint venture with Enbridge Offshore Pipelines LLC, which the Partnership accounts for using the equity method. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas-gathering system and West Cameron dehydration facility. All are located in the Gulf of Mexico and southwestern Louisiana.

The Partnership applies the equity method of accounting for its interests in Starfish. Summarized financial information for 100 percent of Starfish is as follows:

	Three months ended
	March 31, 2006
	(unaudited)
Revenues	$	5,097
Operating income	$	1,429
Net income	$	2,000

Pro Forma Results of Operations

The following table reflects the unaudited pro forma consolidated results of operations for the three months ended March 31, 2005, as though the Starfish acquisition and the Javelina acquisition had occurred on January 1, 2005. The actual results for the three months ended March 31, 2006, are included in the accompanying condensed consolidated statement of operations. The pro forma amounts include certain adjustments, including recognition of depreciation based on the allocated purchase price of property and equipment, amortization of customer contracts, amortization of the excess Starfish purchase price over net book value, amortization of deferred financing costs and interest expense.

The unaudited pro forma results do not necessarily reflect the actual results that would have occurred had the entities been combined during the period presented, nor does it necessarily indicate the future results of the combined entities.

	Three Months Ended
	March 31, 2005
	(in thousands, except per unit data)
Revenue	$	180,281
Net income:	478
Net income per share:

Basic	0.04
Diluted	0.04

Weighted average number of outstanding shares of common stock:
Basic	10,766
Diluted	10,917

MarkWest Energy Partners

Partnership Credit Facility

On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement (“Partnership Credit Facility”), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan. 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 variable interest rate is typically 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 to 1.0%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate. The basis points vary based on the ratio of the Partnership’s Consolidated Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million (“Acquisition Adjustment Period”). The rate at March 31, 2006, was 7.01%, a LIBOR-based rate.

Senior Notes

In October 2004 the Partnership and its subsidiary, MarkWest Energy Finance Corporation, issued $225.0 million in senior notes at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, commencing on May 1, 2005. The notes mature on November 2, 2014. The Partnership may redeem some or all of the notes at any time on or after November 1, 2009, at certain redemption prices together with accrued and unpaid interest to the date of redemption. The Partnership may redeem all of the notes at any time prior to November 1, 2009, at a make-whole redemption price. In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a stated redemption price. The Partnership must offer to repurchase the notes at a specified price if it a) sells certain assets and does not reinvest the proceeds or repay senior indebtedness, or b) the Partnership experiences specific kinds of changes in control. Each of the Partnership’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the 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. They 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 Partnership Credit Facility. The proceeds from these notes were used to pay down the Partnership’s outstanding debt under its credit facility.

The indenture governing the senior notes include certain limitations on the activities of the Partnership and its restricted subsidiaries. Limitations include the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interests of the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. 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 2004 senior notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, is incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer is completed. The registration statement was filed on January 17, 2006, the exchange offer was completed on March 7, 2006, and the interest penalty ceased.

6. Derivative Financial Instruments

Commodity Instruments

MarkWest Hydrocarbon and MarkWest Energy may utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available in the over-the-counter (“OTC”) market, and futures contracts traded on the New York Mercantile Exchange (“NYMEX”). The Company and the Partnership enter into OTC swaps with financial institutions and other energy company counterparties. Management conducts a standard credit review on counterparties and

has agreements containing collateral requirements, where deemed necessary. The Company and the Partnership use standardized agreements that allow for offset of positive and negative exposures. Some of the agreements may require margin deposit.

The use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected, requiring market purchases to meet commitments, or (iii) 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 the Company, or the Partnership, engage in derivative activities, they may be prevented from realizing the benefits of favorable price changes in the physical market; however, they are similarly insulated against unfavorable changes in such prices.

Both the Company and the Partnership have a committee, which is comprised of the senior management team, that oversees all of the hedging activity.

Fair value is based on available market information for the particular derivative instrument, and incorporates the commodity, period, volume and pricing. Positive (negative) amounts represent unrealized gains (losses).

MarkWest Hydrocarbon

The following table summarizes MarkWest Hydrocarbon’s specific derivative positions at March 31, 2006:

Swaps:	Period	Fixed Price		Fair Value at March 31, 2006 (in thousands)
Propane - 6.4 Mm Gal	Oct-Dec 2006	$	0.93	$			(407		)
Propane - 6.4 Mm Gal	Jan-Mar 2007	$	0.96				(257		)

Iso-butane - 0.7 Mm Gal	Oct-Dec 2006	$	1.12				(96		)
Iso-butane - 0.6 Mm Gal	Jan-Mar 2007	$	1.16				(58		)

Normal butane - 2.0 Mm Gal	Oct-Dec 2006	$	1.10				(174		)
Normal butane - 1.7 Mm Gal	Jan-Mar 2007	$	1.13				(96		)

Natural gasoline - 2.1 Mm Gal	Jul-Sep 2006	$	1.47				13

Natural gasoline - 1.3 Mm Gal	Oct-Dec 2006	$	1.39				(86		)
Natural gasoline - 1.1 Mm Gal	Jan-Mar 2007	$	1.37			(94			)
						(1,255			)
Other						(244			)
	Total MarkWest Hydrocarbon				$			(1,499	)

The impact of MarkWest Hydrocarbon’s commodity derivative instruments on results of operations and financial position are summarized below:

	Three months ended March 31, 2006
Unrealized loss – revenue	$	(1,499	)

	Three months ended March 31, 2006
Unrealized loss – current liability	$	1,499

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, NGL’s and crude. Swaps and futures contracts may allow the Partnership to reduce volatility in its margins, because losses or gains on the derivative instruments are generally offset by corresponding gains or losses in the Partnership’s physical positions.

The following table includes information on MarkWest Energy’s specific derivative positions at March 31, 2006:

Costless collars:	Period	Floor		Cap		Fair Value at March 31, 2006 (in thousands)
Crude Oil - 500 Bbl/d	2006	$	57.00	$	67.00	$	(605	)
Crude Oil - 250 Bbl/d	2006	$	57.00	$	67.00	$	(302	)
Crude Oil - 205 Bbl/d	2006	$	57.00	$	65.10	$	(312	)

Propane - 20,000 Gal/d	2006	$	0.90	$	0.99	$	(141	)
Propane - 10,000 Gal/d	2006	$	0.97	$	1.15	$	108
Propane - 12,750 Gal/d	Jan-Jun 2006	$	0.90	$	1.01	$	(5	)

Ethane - 22,950 Gal/d	2006	$	0.65	$	0.80	$	471

Natural gas - 645 Mmbtu/d	Apr-Jun 2006	$	6.71	$	12.46	$	(7	)
Natural gas - 1,575 Mmbtu/d	Apr-Oct 2006	$	8.50	$	10.05	$	725
Natural gas - 1,575 Mmbtu/d	Nov 2006-Mar 2007	$	9.00	$	12.50	$	235
						$	167

Swaps:	Period		Fixed Price		Fair Value at March 31, 2006 (in thousands)
Crude oil - 250 Bbl/d	2006		$	62.00	$	(471	)
Crude oil - 185 Bbl/d	2006		$	61.00	$	(398	)
Crude oil - 250 Bbl/d	2007		$	65.30	$	(365	)

Natural gas basis swap - 10,000 Mmbtu/d	Apr-Oct 2006		$	0.82	$	(672	)
Natural gas basis swap - 10,000 Mmbtu/d	Apr-Oct 2006		$	0.85	$	703
Natural gas basis swap - 4,000 Mmbtu/d	Apr-Oct 2006		$	1.07	$	96
Natural gas basis swap - 4,000 Mmbtu/d	Apr-Oct 2006		$	1.04	$	(87	)
					$	(1,194	)

		Total MarkWest Energy Partners			$	(1,027	)

The impact of MarkWest Energy’s commodity derivative instruments on results of operations and financial position are summarized below:

	Three months ended March 31,
	2006			2005
Realized gains – revenue	$	539		$	42
Unrealized gains (losses) – revenue	(299		)	51
Other comprehensive income – changes in fair value	—			(191		)
Other comprehensive income - settlement	—			42

	March 31,
	2006		2005
Unrealized gains – current asset	$	—	$	9
Unrealized losses – current liability	1,027		450

7. Income Taxes

The Company accounts for income taxes under the asset and liability method pursuant to SFAS No. 109, Accounting for Income Taxes. Under SFAS No. 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 as income 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 $0.4 million for the first three months of 2006 and an income tax expense of $0.8 million for the same period in 2005, resulting in an effective tax rates of 12.6% and 33.4% for each respective period. The change in the annual effective tax rate reflects the utilization of various state net operating losses (“NOL”) and the corresponding change in the state NOL valuation allowance. The Company believes, however, that it is more likely than not that the state NOLs will not be fully realized and continues to maintain a valuation allowance against this long-term deferred tax asset.

8. Stock and Incentive Compensation Plans

Total compensation cost for share-based pay arrangements was as follows:

	Three months ended March 31,
	2006				2005
Stock options	$		21		$		720
Restricted stock	105				14
General partner interests	1,509				1,645
Subordinated units	(13			)	(38			)
Restricted units	458				230
Total compensation cost	2,080				2,571
Income tax benefit	(263			)	(859			)
Net compensation cost	$	1,817			$	1,712

The following summarizes the total compensation cost as of march 31, 2006, related to nonvested awards not yet recognized. The actual compensation cost recognized may differ for the restricted units, as they qualify as liability awards, which are impacted by changes in the fair value.

	Amount		Weighted-average Remaining Vesting Period (years)
Stock options	60		1.7
Restricted stock	669		2.4
Restricted units	1,928		2.4
Total	$	2,657

At March 31, 2006, the Company has four stock-based compensation plans, one of which is through its consolidated subsidiary, MarkWest Energy Partners. These plans are described below.

Stock Options

Stock options are issued under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. The options vest over a service period of from three to five years. The options have a maximum term of ten years. At the discretion of the Company, the holder may use Company-assisted or broker-assisted cashless exercise. The Company may grant options to its employees for up to 925,000 shares of common stock. At March 31, 2006, there were approximately 214,000 options available for grant under this plan. The Company may grant options to its non-employee directors for up to 30,000 shares of common stock, however, it does not intend to use options as a compensation tool in the future.

The fair value of stock options is estimated using the Black-Scholes option-pricing model. No options were granted in 2006 or 2005.

Under SFAS No. 123R, compensation expense is based on the fair value of the stock options, reduced for an estimate of expected forfeitures (4.6% in the first quarter of 2006).

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

	Three Months Ended March 31,
	2006	2005
Options exercised, cashless	7	20
Shares issued, cashless	4	12
Options exercised, cash	7	5
Shares issued, cash	5	5

A summary of the status of the Company’s stock option plans as of March 31, 2006 and 2005 are presented below. Stock option information in the following table has not been adjusted to give retroactive effect to stock dividends paid.

	Number of Shares		Weighted- average Exercise Price			Weighted-average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at December 31, 2005	114,007		$		8.28	7	$		1,356,919
Changes during the quarter:
Granted	—		—			—	—

Exercised	(13,705	)	7.32			5	212,634
Forfeited	—		—			—	—
Expired	—		—			—	—

Outstanding at March 31, 2006	100,302		$	8.41		6	$	1,453,758

Exercisable at March 31, 2006	66,179
Exercisable at March 31, 2005	72,595

	March 31,
	2006		2005
Total fair value of options vested during the quarter	$	22,352	$		35,697
Total intrinsic value of options exercised during the quarter	$	212,634	$	339,582

Restricted Stock

The Company also issues restricted stock, for no consideration, under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. The restricted stock vests over a service period of three years. The fair value of restricted stock is determined on the date of grant, based on the fair value of the common stock. The holder of restricted stock receives dividends as though the shares were unrestricted. Upon settlement, the individual receives common stock of the Company. Under SFAS No. 123R, compensation expense is based on the fair value, reduced for an estimate of expected forfeitures (4.6% in the first quarter of 2006).

The following summarizes the impact of the Company’s restricted stock plans (in thousands, except for per share data):

	Number of Shares		Weighted-average Grant-date Fair Value
Nonvested at January 1, 2006	22,673		$	21.24
Granted	15,651		24.00
Vested	(2,327	)	19.16
Forfeited	—		—
Nonvested at March 31, 2006	35,997		$	22.57

	Three Months Ended March 31,
	2006		2005
Weighted-average grant-date fair value of restricted stock granted during the quarter	$	375,624	$	133,603
Total fair value of restricted stock vested during the quarter	44,585		—

During the quarters ended March 31, 2006 and 2005, the Company received no proceeds for issuing restricted stock, and there were no cash settlements.

Participation Plan

The subordinated units are sold without any restrictions on transfer. Compensation expense is based on changes in the market value of the subordinated units. No subordinated units were sold to the employees or directors in 2006 or 2005. MarkWest Hydrocarbon reacquired no subordinated units in 2006 or 2005. During the quarters ended March 31, 2006 and 2005, the Company received no proceeds for issuing subordinated units, and there were no cash settlements or conversions to common units.

The interest in the Partnership’s general partner is sold with certain put-and-call provisions that allow the individuals to require MarkWest Hydrocarbon to buy back, or require the individuals to sell back their interest in the general partner to

MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWest Hydrocarbon or the Partnership’s general partner undergoes a change of control; (2) additional membership interests are issued that, on a pro forma basis, decreases the distributions to all the then existing members; (3) any amendment, alteration or repeal of the provisions of the general partner agreement is undertaken which materially and adversely affects the then existing rights, duties, obligations or restrictions of the employees and directors; or (4) the employee or director (i) becomes totally disabled while a director, officer or employee of the general partner, of MarkWest Hydrocarbon or of any of their affiliates, or (ii) dies, or (iii) retires as a director, officer or employee of the general partner, of MarkWest Hydrocarbon or of any of their affiliates after reaching the age of 60 years. The employee or his estate has 120 days after the put event to exercise the put under (4) and 30 days after notice to exercise under (1) through (3). MarkWest Hydrocarbon can exercise its call option if the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates, or if there is a change of control. MarkWest Hydrocarbon can exercise its call option if (i) the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates, or (ii) if there is a change of control of MarkWest or of the Partnership’s general partner. For the call option based upon a termination of the employment or directorship, MarkWest Hydrocarbon has 12 months following the termination date of the employee or director to exercise its call option. MarkWest Hydrocarbon has agreed to exempt the general partner interests of three present or former directors from the call option based upon a termination of employment or directorship. Additionally, pursuant to the terms of Mr. Semple’s employment agreement with MarkWest Hydrocarbon, 66% of his general partner interest has become exempt from the call option based upon a termination of employment or directorship for other than cause, and the remaining 34% will likewise become exempt after November 1, 2006. For the call option based upon a change of control of MarkWest or of the Partnership’s general partner, MarkWest Hydrocarbon has 30 days following the change of control to exercise its call option.

As the formula used to determine the sale and buy-back price is not based on an independent third party valuation, coupled with the attributes of the put-and-call provisions, these transactions are considered compensatory arrangements, similar to a stock appreciation right. Compensation expense related to general partner interests is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and directors to repurchase the general partner interests, and is based on the current market value of the Partnership’s common units and the current quarterly distributions paid. During the quarters ended March 31, 2006 and 2005, the Company received $0.3 million and $0.2 million, respectively, for issuing, and distributed $0.2 million and $0, respectively, to repurchase general partner interests.

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

The general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of the general partner, as well as employees of its affiliates who perform services for us. The plan consists of two components, restricted units and unit options. The plan currently permits the grant of awards covering an aggregate of 500,000 common units, comprised of 200,000 restricted units and 300,000 unit options. The Compensation Committee of the general partner’s Board of Directors administers the plan.

Restricted Units. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units vest over a service period of three to four years; however, vesting for certain awards accelerates if specific annualized distribution goals are met. These restricted units are entitled, during the vesting period, to receive distribution equivalents, which represent cash equal to the amount of distributions made on common units.

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

	Number of units		Weighted-average grant-date fair value
Non-vested at December 31, 2005	38,864		$	45.60
Granted	30,293		46.64
Vested	(9,643	)	46.44
Forfeited	—		—
Non-vested at March 31, 2006	59,514		$	46.00

	March 31,
	2006		2005
Weighted-average grant-date fair value of restricted units granted during the quarter	$	1,412,993	$	385,994
Total fair value of restricted units vested during the quarter	447,841		69,025
Total intrinsic value of restricted units exercised during the quarter	$	965,152	$	316,969

During the quarters ended March 31, 2006 and 2005, the Partnership received no proceeds for issuing restricted units, and there were no cash settlements.

Of the total number of restricted units that vested in the first quarter of 2006 and 2005, the Partnership did not redeem any restricted units for cash. It issued 9,643 common units in 2006. In 2005, the Partnership issued 8,850 common units and acquired 250 more common units in the open market. The Partnership recorded $0.5 million and $0.2 million in compensation expense for the three months ended March 31, 2006 and 2005, respectively.

Unit Options. The Compensation Committee makes grants of unit options under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, at the discretion of the committee, may be less than, equal to or more than the fair market value of the units on the date of grant. Unit options are exercisable over a period determined by the Compensation Committee. Unit options also are exercisable upon a change in control of us, the general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.

As of March 31, 2006, the Partnership had not granted common unit options to employees or directors of the general partner, or employees of its affiliates or members of senior management.

9. Dividends to Shareholders

Cash Dividends

On January 26, 2006, the Company’s Board of Directors declared a quarterly cash dividend of $0.125 per share, payable on February 22, 2006, to the stockholders of record as of the close of business on February 15, 2006. The ex-dividend date was February 13, 2006.

On April 27, 2006, the Company’s Board of Directors declared a quarterly cash dividend of $0.175 per share, an increase of $0.10 per share from the same period of 2005, payable on June 5, 2006, to the stockholders of record as of the close of business on May 26, 2006. The ex-dividend date will be May 24, 2006.

Stock Dividends

On April 27, 2006, the Board of Directors declared a stock dividend of one share of common stock for each ten shares of common stock held by stockholders of record as of the close of business on May 11, 2006. The stock dividend is to be paid on May 23, 2006, with an ex-dividend date of May 9, 2006.

10. Commitments and Contingencies

Legal

In the ordinary course of business, the Company is subject to a variety of risks and disputes normally incident to its business and is a party to various legal proceedings. We maintain insurance policies in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business interruption to the Company or for third party claims of personal and property damage, or that the coverages or levels of insurance it presently has will be available in the future at economical prices.

In early 2005, MarkWest Hydrocarbon, Inc., the Partnership and several of its affiliates were served with two lawsuits, Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al. (filed February 2, 2005), and Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al. (filed February 8, 2005), in Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137 and Civil Action No. 05-CI-00156, which actions on February 24, 2005, were removed to the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. The Company, the Partnership and its affiliates were served with an additional lawsuit, Community Trust and Investment Co., et al. v. MarkWest Hydrocarbon, Inc. et al., filed November 7, 2005,in Floyd County Circuit Court, Kentucky, that added five new claimants but essentially alleged the same facts and claims as the earlier two suits. On March 27, 2006, the U.S. District Court remanded the cases back to Floyd County Circuit Court, Kentucky.

These actions are for third-party claims of property and personal injury damages sustained as a consequence of an NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004. The pipeline was owned by an unrelated business entity and leased and operated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC. It transports NGLs from the Maytown gas processing plant to the Partnership’s Siloam fractionator. The fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The pipeline owner, the U.S. Department of Transportation, Office of Pipeline Safety (“OPS”), and the Partnership continue to investigate the incident. Discovery in the action is now just getting underway following the remand back to state court.

The Company notified its general liability insurance carriers of the incident and the lawsuits in a timely manner and is coordinating its legal defense with the insurers. At this time, the Company believes that it has adequate general liability insurance coverage for third-party property damage and personal injury liability resulting from the incident. The Company has settled with several of the claimants for third-party property damage claims (damage to residences and personal property), and reached settlements for some of the personal injury claims. These have been paid for or reimbursed under the Company’s general liability insurance. As a result, the Company has not provided for a loss contingency.

Pursuant to OPS regulation mandates and to a Corrective Action Order issued by the OPS November 18, 2004, pipeline and valve integrity evaluation, testing and repairs were conducted on the affected pipeline segment before service could be resumed. OPS authorized a partial return to service of the affected pipeline in October 2005. MarkWest is in the process of applying for return to full service.

Related to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership has filed an independent 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 its All-Risks Property and Business Interruption insurance carriers as a result of the companies’ refusal to honor their insurance coverage obligation to pay the Company for certain expenses. These include the Company’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment, 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). These 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 they are received. The Company has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Company will ultimately recover under these policies. The Company has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with its owner, pursuant to the terms of the pipeline lease agreement.

The Company has also been involved in a lawsuit captioned Ross Bros. Construction v. MarkWest Hydrocarbon, Inc., (U.S. Court Appeals for the Sixth Circuit, Case No. 05-6251). This lawsuit involved the expansion construction of the Siloam Kentucky gas processing and fractionation plant and a dispute as to the monetary value of work and additional work beyond the contract’s lump sum price performed by the contractor. This lawsuit involved a claim of approximately $0.7 million in extra costs. The Company was recently granted Summary Judgment on its defense asserting accord and satisfaction. In August 2005, Plaintiffs filed an appeal of the Summary Judgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that, while it is not able to predict the outcome of this matter, based on the judge’s discussion on the grant of the summary judgment and denial of Ross Brothers’ motion for reconsideration, it is probable that the Company will prevail in the appeal. As a result, the Company has not provided for a loss contingency.

The Company has been involved in an arbitration proceeding captioned Kevin Stowe and Scott Daves v. MarkWest Hydrocarbon, Inc., American Arbitration Association arbitration, Case No. 77 168 Y 0052 05 BEAH, Denver, Colorado, 2005. Claimants filed an arbitration proceeding against the Company seeking further payments out of a dispute and

settlement over interests in certain wells in Colorado. In February 2006, the Arbitrator in the action granted MarkWest’s motion for summary judgment and the arbitration action was dismissed with prejudice.

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

11. Subsequent Events

Headquarters Office Lease

In April 2006, the Partnership entered into a ten-year office lease and will relocate its and MarkWest Hydrocarbon, Inc.’s corporate headquarters to the Park Central Building, Tower II, 1515 Arapahoe Street, Suite 700, Denver, Colorado 80202. The lease provides for a tenant improvement allowance of up to approximately $1.8 million through December 31, 2006. A security deposit of $1.0 million was provided in the form of an irrevocable letter of credit. The future minimum lease payments of the new lease are as follows:

Year ending December 31,
2006	$	—
2007	927,442
2008	972,138
2009	1,016,834
2010	1,044,769
Thereafter	5,983,677
Total	$	9,944,860

The Company’s headquarters is currently in a building leased by MarkWest Hydrocarbon. A portion of the lease cost for that building has historically been allocated to both the Company and the Partnership. MarkWest Hydrocarbon has not determined the final disposition of its existing lease; however, a portion of incremental expense, if any, may potentially be allocated to the Partnership.

S-1 Registration Statement

On April 20, 2006, the Partnership filed a Form S-1 registration statement registering units issued in the fourth quarter of 2005 under private placement offerings. The Partnership will receive no proceeds from the sale of any units offered under this registration statement.

On April 25, 2006, the Partnership filed a Form S-1 registration statement for a new unit issuance offering. The Partnership expects to offer up to 3.85 million new units.

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. Since February 2004, the Company is also engaged in the wholesale marketing of propane. 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. There were no intersegment revenues prior to May 24, 2002. The Company conducts its continuing operations in the United States.

The table below presents information about net income/(loss) for the reported segments for the three months ended March 31, 2006 and 2005. Net income/(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 (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.

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
Quarter ended March 31, 2006:
Revenues	$	100,593		$	156,743		$	(17,715	)	$	239,621
Purchased product costs	92,025			100,797			(11,655		)	181,167
Facility expenses	5,770			13,994			(6,060		)	13,704
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
Operating income (loss)	(445		)	22,400			—			21,955
Other income (expense):
Earnings from unconsolidated subsidiary	—			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
Other income	150			2,092			—			2,242
Income 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		)
Net income	$	(497	)	$	13,873		$	(10,544	)	$	2,832

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
Quarter ended March 31, 2005:
Revenues	$	64,521		$	89,637		$	(15,805	)	$	138,353
Purchased product costs	53,821			60,785			(9,907		)	104,699
Facility expenses	5,827			9,331			(5,898		)	9,260
Selling, general and administrative expenses	3,463			4,639			—			8,102
Depreciation	415			4,326			—			4,741
Amortization of intangible assets	—			2,095			—			2,095
Accretion of asset retirement and lease obligations	—			10			—			10
Operating income (loss)	995			8,451			—			9,446
Other income (expense):
Interest income	182			67			—			249
Interest expense	(30		)	(3,674		)	—			(3,704		)
Amortization of deferred financing costs (a component of interest expense)	(61		)	(475		)	—			(536		)
Dividend income	92			—			—			92
Other income	191			(104		)	—			87
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	1,369			4,265			—			5,634
Income tax expense	(770		)	—			—			(770		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(3,325		)	(3,325		)
Net income	$	599		$	4,265		$	(3,325	)	$	1,539

Other income for the three months ended March 31, 2006, includes $1.8 million in earnings for insurance recoveries related to charges incurred in 2005 from Hurricane Rita.

In the fourth quarter of 2004, the Partnership received a communication from a customer alleging a measurement or volume discrepancy with the Partnership. Based on the evidence available at that time, the Partnership recorded a contingent liability of approximately $1.9 million. In the first quarter of 2006, after a thorough investigation, management of the Partnership concluded that it was no longer probable that a liability existed with respect to the alleged measurement or volume discrepancy. Accordingly, the $1.9 million accrued liability was reversed to revenue in the first quarter of 2006.

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

Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking. Statements included in this quarterly report on Form 10-Q that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as “may,” “believe,” “estimate,” “expect,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

These forward-looking statements are made based upon management’s expectations, estimates, assumptions and beliefs concerning future events impacting 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 in the forward-looking statements.

Forward-looking statements include statements relating to, among other things:

• Our expectations regarding MarkWest Energy Partners, L.P.

• Our ability to grow MarkWest Energy Partners, L.P.

• Our ability to amend certain producer contracts.

• Our expectations regarding natural gas, NGLs product 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.

• Our ability to comply with environmental and governmental regulations.

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

• The availability of raw natural gas supply for our gathering and processing services.

• The availability of NGLs for our transportation, fractionation and storage services.

• Prices of NGL products and natural gas, including the effectiveness of any hedging activities.

• Our ability to negotiate favorable marketing agreements.

• The risks that third party natural gas exploration and production activities will not occur or be successful.

• Our dependence on certain significant customers, producers, gatherers, treaters and transporters of natural gas.

• Competition from other NGL processors, including major energy companies.

• Our dependence on certain significant customers, producers, gatherers, treaters and transporters of natural gas.

• Our substantial debt and other financial obligations could adversely impact our financial condition.

• Our ability to successfully integrate our recent or future acquisitions.

• Our ability to identify and complete organic growth projects or acquisitions complementary to our business.

• 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.

• Changes in general economic conditions in regions in which our products are located.

• The threat of terrorist attacks or war.

• Winter weather conditions.

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. You should read “Risk Factors” included in Item 1A of this Form 10-K for further information.

Overview

MarkWest Hydrocarbon reported net income of $2.8 million, or $0.26 per diluted share, for the three months ended March 31, 2006, compared to net income of $1.5 million, or $0.14 per diluted share, for the corresponding quarter of 2005. The Company reports its results under accounting principles generally accepted in the United States (“GAAP”), which require that the Company consolidate MarkWest Energy Partners.

MarkWest Hydrocarbon Standalone Results

For the three months ended March 31, 2006, MarkWest Hydrocarbon Standalone reported an operating loss of $0.4 million, compared to operating income of $1.0 million in 2005. MarkWest Hydrocarbon Standalone reported a net loss of $0.5 million in 2006, compared to net income of $0.6 million in 2005, for the comparable period.

Cash Dividends

Stock Dividends

MarkWest Energy Partners Results

For the three months ended March 31, 2006, the Partnership reported operating income of $22.4 million compared to $8.5 million for the corresponding quarter of 2005, an increase of $13.9 million, or 165%. The Partnership reported net income of $13.9 million in the first quarter of 2006, compared to $4.3 million in 2005.

Our Business

MarkWest Hydrocarbon was founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering of common shares in 1996.

MarkWest Hydrocarbon is an energy company primarily focused on marketing natural gas liquids (NGLs) 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. 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.

MarkWest Hydrocarbon’s assets consist primarily of partnership interests in MarkWest Energy Partners and certain processing agreements in Appalachia. As of March 31, 2006, the Company owned a 21% interest in the Partnership, consisting of the following:

• 1,633,334 subordinated units and 836,162 common units, representing a 19% limited partner interest in the Partnership; and

• an 89% 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:

• The nature of the business from which we derive our revenues and from which MarkWest Energy Partners derives its revenues;

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

• The lack of comparability within our results of operations across periods because of MarkWest Energy Partners’ significant acquisition activity.

MarkWest Hydrocarbon

Excluding the revenues derived from MarkWest Energy Partners, we generate the majority of our revenues and net operating margin (defined and discussed further, below) from our Appalachia processing agreements. We outsource these services to the Partnership, and pay the Partnership a fee for providing processing and fractionation services. As compensation for providing processing services to our Appalachian producers, we earn a fee and receive title to the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu value of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a “keep-whole” arrangement. In keep-whole arrangements, our principal cost is purchasing and delivering dry gas of an equivalent Btu content to replace Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread.” Generally, the frac spread is positive and offsets all or a portion of the fees that we pay the Partnership. In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, and the associated fees that we pay the Partnership, the net operating margin associated with the Appalachian processing agreements results in operating losses.

In Appalachia, we have entered into operating agreements with a customer with respect to natural gas delivered into its transmission facilities, upstream of MarkWest Energy Partners’ 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 shipped by the customer, on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through December 31, 2015, with annual renewals thereafter.

At the closing of MarkWest Energy Partners’ initial public offering on May 24, 2002, we outsourced our midstream services to the Partnership. Pursuant to the terms of the operating agreements, we retained all the benefits and associated risks of our keep-whole contracts with producers. Our NGL marketing and natural gas supply operations were retained by us and not contributed to MarkWest Energy Partners.

In September 2004, we entered into several new and amended agreements, expiring December 31, 2009, with one of the largest Appalachia producers, which allow us to significantly reduce our exposure to commodity price risk, for approximately 25% of our keep-whole gas volumes. Under these agreements, the Company’s exposure to the keep-whole natural gas is limited in the event natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring operating losses.

Beginning in 2006, we also entered into derivative instruments, which are marked to market, to manage our risks related to commodity price exposure. Our keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which, in turn, may increase the volatility of our standalone results and cash flows. We attempt to mitigate our commodity price risk through our commodity price risk management program (see Item 3, “Quantitative and Qualitative Disclosures about Market Risk” for further details about our commodity price risk management program).

Our natural gas marketing group markets natural gas for MarkWest Energy Partners’ facilities, purchases replacement Btu gas requirements and assists with business development efforts. We also purchase and resell natural gas obtained from third parties. Beginning in February 2004, we initiated a wholesale propane marketing business. We buy propane on a wholesale basis and resell it to third parties, primarily propane retailers. This operation is, fundamentally, a high-dollar, low margin business. MarkWest Hydrocarbon also enters into future sale agreements that, as derivative instruments, are marked to market.

MarkWest Hydrocarbon also receives revenue under fee-based arrangements for processing natural gas.

MarkWest Energy Partners

The Partnership generates the majority of its revenues and net operating margin (defined and discussed further, below) 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 types of arrangements:

• Fee-based arrangements. Under 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; however, the Partnership’s revenues from these arrangements would be reduced.

• Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas 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 to the producer, 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 generally increase as natural gas prices and NGL prices increase, and its revenues and net operating margins decrease as natural gas and NGL prices decrease

• Percent-of-index arrangements. Under 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, their net operating margins increase during periods of high natural gas prices.

• Keep-whole arrangements. Under keep-whole arrangements, the Partnership gathers natural gas from the producer, processes the natural gas, and sells the resulting NGLs to third parties at market prices. Because the extraction of the 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, its revenues and net operating margins increase as the price of NGLs increases relative to the price of natural gas, and decreases as the price of natural gas increases relative to the price of 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.

• Condensate sales. During the gathering process, thermodynamic forces contribute to changes in operating conditions of the natural gas flowing through the pipeline infrastructure. As a result, hydrocarbon dew points are reached, causing condensation of hydrocarbons in the high-pressure pipelines. Condensate collected in the system is sold at a monthly crude-oil index-based price, and the proceeds are retained

In many cases, it provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of the Partnership’s contracts vary based on gas quality conditions, the competitive environment at the time 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.

At March 31, 2006, 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 half, 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. Because of the Partnership’s ability to operate the plant in several recovery modes, including turning it off, coupled with the additional fees provided for in the gas gathering contracts, its overall keep-whole contract exposure is limited to a small portion of the operating costs of the plant. For the three months ended March 31, 2006, approximately 7.7% of East Texas inlet volumes were processed pursuant to keep-whole contracts.

For the three months ended March 31, 2006, MarkWest Energy Partners generated the following percentages of its revenues and net operating margin from the following types of contracts:

	Fee-Based		Percent-of- Proceeds (1)		Percent-of- Index (2)		Keep- Whole (3)		Total
Revenues	11	%	18	%	31	%	40	%	100	%
Net operating margin	33	%	31	%	24	%	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.

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 profits interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with accounting principles generally accepted in the United States (“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 quarter ended March 31, 2006, we accounted for 11% of the Partnership’s revenues and 14% of its net operating margin. This represents a decrease from the quarter ended March 31, 2005, when we accounted for 13% of the Partnership’s revenues and 20% of its net operating margin. We expect we will continue to account for less of the Partnership’s business in the future as it continues to acquire assets and increase its customer base or diversify its business.

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.

Impact of Recent Acquisitions on Comparability of Financial Results

Recent MarkWest Energy Partners Acquisition Activity

In reading the discussion of our historical results of operations, you should be aware of the impact of our recent acquisitions, which fundamentally affect the comparability of our results of operations over the periods discussed.

Since the Partnership’s initial public offering, it has completed eight acquisitions for an aggregate purchase price of approximately $794 million, net of working capital. The following table sets forth information regarding each of these acquisitions:

Name	Assets	Location	Consideration (in millions)		Closing Date
Javelina (1)	Gas processing and fractionation facility	Corpus Christi, TX	$	398.3	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 procession 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

Operating Data

	Three Months Ended March 31,
	2006	2005	% Change
MarkWest Hydrocarbon Standalone:
*Frac Spread*
NGL product sales (gallons) (1)	49,967,000	52,164,000	-4.2	%

*Marketing*
NGL product sales (gallons) (2)	27,196,000	19,672,332	38.2	%

MarkWest Energy Partners:
*East Texas* (3)
Gathering systems throughput (Mcf/d)	346,000	287,000	20.6	%
NGL product sales (gallons)	35,436,000	27,612,000	28.3	%

*Oklahoma*
Foss Lake gathering systems throughput (Mcf/d)	87,600	67,000	30.7	%
Arapaho NGL product sales (gallons)	18,417,000	15,217,000	21.0	%

*Other Southwest* (4)
Appleby gathering systems throughput (Mcf/d)	33,500	28,000	19.6	%
Other gathering systems throughput (Mcf/d)	19,100	17,000	12.4	%
Lateral throughput volumes (Mcf/d)	49,700	52,000	-4.4	%

*Appalachia* (5)
Natural gas processed for a fee (Mcf/d)	205,000	210,000	-2.4	%
NGLs fractionated for a fee (Gal/day)	449,000	462,000	-2.8	%
NGL product sales (gallons)	10,482,000	10,765,000	-2.6	%

*Michigan*
Natural gas processed for a fee (Mcf/d)	6,300	6,900	-8.7	%
NGL product sales (gallons)	1,449,000	1,563,000	-7.3	%
Crude oil transported for a fee (Bbl/d)	14,000	14,100	-0.7	%

*Gulf Coast* (6)
Natural gas processed for a fee (Mcf/d)	120,000	NA	NA
NGLs fractionated for a fee (Gal/day)	820,000	NA	NA

(1) Represents sales at the Siloam fractionator.

(2) Represents sales from our wholesale business.

(3) MarkWest Energy Partners acquired the East Texas System in late July 2004.

(4) MarkWest Energy Partners acquired the Lubbock pipeline (a/k/a the Power-tex Lateral Pipeline) in September 2003 and the Hobbs lateral pipeline in April 2004. The Lubbock and Hobbs pipelines are the only laterals the Partnership owns that produce revenue on a per-unit-of-throughput basis. MarkWest Energy Partners receive a flat fee from our other lateral pipelines and, consequently, the throughput data from these lateral pipelines is excluded from this statistic.

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

(6) MarkWest Energy Partners acquired the Javelina system (Gulf Coast) on November 1, 2005.

Financial Results

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 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 includes a reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
Quarter ended March 31, 2006:
Revenues	$	100,593		$	156,743		$	(17,715	)	$	239,621
Purchased product costs	92,025			100,797			(11,655		)	181,167
Net operating margin	8,568			55,946			(6,060		)	58,454
Facility expenses	5,770			13,994			(6,060		)	13,704
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
Operating income (loss)	(445		)	22,400			—			21,955
Other income (expense):
Earnings from unconsolidated subsidiary	—			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
Other income	150			2,092			—			2,242
Income 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		)
Net income	$	(497	)	$	13,873		$	(10,544	)	$	2,832

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
Quarter ended March 31, 2005:
Revenues	$	64,521		$	89,637		$	(15,805	)	$	138,353
Purchased product costs	53,821			60,785			(9,907		)	104,699
Net operating margin	10,700			28,852			(5,898		)	33,654
Facility expenses	5,827			9,331			(5,898		)	9,260
Selling, general and administrative expenses	3,463			4,639			—			8,102
Depreciation	415			4,326			—			4,741
Amortization of intangible assets	—			2,095			—			2,095
Accretion of asset retirement and lease obligations	—			10			—			10
Operating income (loss)	995			8,451			—			9,446
Other income (expense):
Interest income	182			67			—			249
Interest expense	(30		)	(3,674		)	—			(3,704		)
Amortization of deferred financing costs (a component of interest expense)	(61		)	(475		)	—			(536		)
Dividend income	92			—			—			92
Other income	191			(104		)	—			87
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	1,369			4,265			—			5,634
Income tax expense	(770		)	—			—			(770		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(3,325		)	(3,325		)
Net income	$	599		$	4,265		$	(3,325	)	$	1,539

MarkWest Hydrocarbon Standalone

Revenues. Revenues increased $36.1 million, or 56%, for the three months ended March 31, 2006, compared to the corresponding quarter of 2005. This was due primarily to approximately a $25.8 million increase in our propane wholesale and natural gas marketing business, attributable to a 35% increase in volumes and a 65% increase in prices. Frac spread revenues increased approximately $10.5 million, attributable to a 32% increase in prices, offset by a 4% decrease in volumes. The mark to market adjustment for derivative instruments decreased revenue by approximately $1.5 million and $0, respectively, in 2006 and 2005.

Purchased Product Costs. Purchased product costs increased $38.2 million, or 71%, for the three months ended March 31, 2006, compared to the corresponding quarter of 2005. This was due primarily to approximately a $24.3 million increase in our propane wholesale and natural gas marketing business, attributable to a 35% increase in volumes and a 65% increase in prices. Frac spread product costs increased approximately $13.9 million, primarily due to a 45% increase in costs, offset by a 4% decrease in volumes.

Facility Expenses. Facility expenses decreased by approximately $0.1 million, or 1%, during the three months ended March 31, 2006, compared to corresponding quarter of 2005 primarily as a result of favorable fuel reimbursement at our Kenova, Cobb and Boldman facilities.

Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased by $0.4 million, or 12%, during the three months ended March 31, 2006, compared to the corresponding quarter of 2005 as a result of a $0.2 million decrease in compensation expense attributed to the 1996 Stock Incentive Plan and 1996 Non-employee

Director Stock Option Plan, and an increase to the allocation of selling, general and administrative expenses to the Partnership due to the increased activities, such as acquisitions.

Depreciation. Depreciation expense decreased by $0.2 million, or 51%, during the three months ended March 31, 2006, compared to the corresponding quarter of 2005, due to fixed assets becoming fully depreciated in 2005.

Income taxes. Income tax expense decreased by $0.4 million, or 51%, due to the decrease in net income in the three months ended March 31, 2006, compared to the corresponding quarter of 2005. The change in the annual effective tax rate reflects the utilization of various state net operating losses (“NOL”) and the corresponding change in the state NOL valuation allowance. The Company believes, however, that it is more likely than not that the state NOLs will not be fully realized and continues to maintain a valuation allowance against this long-term deferred tax asset.

MarkWest Energy Partners

Revenues. Revenues for the three months ended March 31, 2006, increased by $67.1 million, or 75%, compared to the corresponding quarter of 2005, due to the Partnership’s Javelina acquisition in November 2005, which contributed $15.0 million, as well as increased volumes and prices in Oklahoma of $25.0 million, in East Texas of $17.8 million, and in Other Southwest of $7.3 million.

Purchased Product Costs. Purchased product costs increased during the three months ended March 31, 2006 by $40.0 million, or 66%, compared to the corresponding quarter of 2005. The increase was due primarily to increased volumes in Oklahoma of $22.8 million and in Other Southwest of $6.7 million, as well as increased volumes and prices in East Texas of $9.6 million.

Facility Expenses. Facility expenses increased approximately $4.7 million, or 50%, during the three months ended March 31, 2006, compared to the corresponding quarter of 2005, primarily due to the Partnership’s November 2005 Javelina Acquisition, which contributed $1.9 million, and $1.3 million related to the new Carthage facility in East Texas , which started operations on January 1, 2006.

Selling, General and Administrative Expenses. Selling, general and administrative expenses (“SG&A”) increased $3.7 million, or 80%, during the three months ended March 31, 2006, relative to the comparable period in 2005. The increase related primarily to additional audit and Sarbanes Oxley professional fees of $1.3 million. Our acquisitions and overall growth led to increased labor costs from additional personnel of $1.1 million and increased insurance premiums of $0.9 million.

Earnings from Unconsolidated Subsidiary. Earnings from unconsolidated affiliates during the three months ended March 31, 2006, increased as a result of the March 31, 2005, acquisition of Starfish.

Interest Expense and Amortization of Deferred Financing Costs (a component of interest expense). Interest expense increased by $7.3 million, or 199%, during the three months ended March 31, 2006, compared to 2005, primarily as a result of the additional debt related to the Starfish and Javelina acquisitions.

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. Within our Gulf Coast Business Unit, our Starfish operations have been substantially curtailed since shortly before the hurricanes hit the Gulf Coast. Until necessary repairs are completed, Starfish will not be able to fully return to normal operations, which will have a continuing impact on our operating income. We are submitting insurance claims for both business interruption and property damage purposes, and we have engaged in conversations with our insurer and adjuster and have begun to recover expenses and losses incurred since the hurricane (less the insurance deductibles) during 2006.

The resulting loss to both offshore and onshore assets led to substantial insurance claims within the oil and gas industry. Along with other industry participants, we expect our insurance costs to increase within this region as a result of these developments. We are currently negotiating with our insurer regarding the renewal of our insurance coverage relating to Starfish. We are also exploring alternatives to mitigate the significant cost increases we are facing, including reduced coverage levels, higher deductibles and self insurance retentions.

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. A committee, comprised of members of the senior management team, oversees all of our derivative activity.

We may 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.

The use of derivative instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGL’s 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, NGL’s 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 Risk Management Activity

MarkWest Hydrocarbon may enter into physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of purchases and sales, direct exposure to price volatility can be created, because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and derivatives activities, direct exposure may occur naturally, or we may choose direct exposure when we favor that exposure over frac spread risk. Beginning in 2006, MarkWest Hydrocarbon pre-purchased natural gas for shrink requirements in future months and, for both natural gas and NGLs, has entered into swaps and future sales agreements to manage frac spread risk. These derivative instruments are marked to market.

The following table summarizes MarkWest Hydrocarbon’s specific derivative positions at March 31, 2006:

Swaps:	Period		Fixed Price		Fair Value at March 31, 2006 (in thousands)
Propane - 6.4 Mm Gal	Oct-Dec 2006		$	0.93	$	(407	)
Propane - 6.4 Mm Gal	Jan-Mar 2007		$	0.96	(257		)

Iso-butane - 0.7 Mm Gal	Oct-Dec 2006		$	1.12	(96		)
Iso-butane - 0.6 Mm Gal	Jan-Mar 2007		$	1.16	(58		)

Normal butane - 2.0 Mm Gal	Oct-Dec 2006		$	1.10	(174		)
Normal butane - 1.7 Mm Gal	Jan-Mar 2007		$	1.13	(96		)

Natural gasoline - 2.1 Mm Gal	Jul-Sep 2006		$	1.47	13
Natural gasoline - 1.3 Mm Gal	Oct-Dec 2006		$	1.39	(86		)
Natural gasoline - 1.1 Mm Gal	Jan-Mar 2007		$	1.37	(94		)
					(1,255		)
Other					(244		)

		Total MarkWest Hydrocarbon			$	(1,499	)

The impact of MarkWest Hydrocarbon’s commodity derivative instruments on results of operations and financial position are summarized below:

	Three months ended March 31,
	2006
Unrealized loss – revenue	$	(1,499	)

	March 31,
	2006
Unrealized loss – current liability	$	1,499

The following table summarizes MarkWest Hydrocarbon’s physical inventory position at March 31, 2006, which could be used in a number of ways, including satisfying shrink requirements or physically settling future sales commitments:

Product	Quantity	Units of Measure	Weighted Average Cost at March 31, 2006		Total Cost at March 31, 2006
Natural gas	785,000	Mmbtu	$	7.56	$	5,933
NGLs	5,206,000	Gallons	$	0.88	4,606

		Total MarkWest Hydrocarbon			$	10,539

Natural gas, purchased in March 2006 for April 2006 delivery	1,740,010	Mmbtu	$	7.46	$	12,972

The Company entered into the following future sale contracts in May, 2006:

Future sale contracts:	Period	Weighted Average Price
Propane - 1.0 Mm Gal	Nov-Dec 2006	$		1.07
Propane - 1.0 Mm Gal	Jan-Feb 2007	$	1.08

The Partnership’s Derivative Activity

The following table includes information on MarkWest Energy’s specific derivative positions at March 31, 2006:

Costless collars:	Period	Floor		Cap		Fair Value at March 31, 2006 (in thousands)
Crude Oil - 500 Bbl/d	2006	$	57.00	$	67.00	$	(605	)
Crude Oil - 250 Bbl/d	2006	$	57.00	$	67.00	$	(302	)
Crude Oil - 205 Bbl/d	2006	$	57.00	$	65.10	$	(312	)

Propane - 20,000 Gal/d	2006	$	0.90	$	0.99	$	(141	)
Propane - 10,000 Gal/d	2006	$	0.97	$	1.15	$	108
Propane - 12,750 Gal/d	Jan-Jun 2006	$	0.90	$	1.01	$	(5	)

Ethane - 22,950 Gal/d	2006	$	0.65	$	0.80	$	471

Natural gas - 645 Mmbtu/d	Apr-Jun 2006	$	6.71	$	12.46	$	(7	)
Natural gas - 1,575 Mmbtu/d	Apr-Oct 2006	$	8.50	$	10.05	$	725
Natural gas - 1,575 Mmbtu/d	Nov 2006-Mar 2007	$	9.00	$	12.50	$	235
						$	167

Swaps:	Period		Fixed Price		Fair Value at March 31, 2006 (in thousands)
Crude oil - 250 Bbl/d	2006		$	62.00	$	(471	)
Crude oil - 185 Bbl/d	2006		$	61.00	$	(398	)
Crude oil - 250 Bbl/d	2007		$	65.30	$	(365	)

Natural gas basis swap - 10,000 Mmbtu/d	Apr-Oct 2006		$	0.82	$	(672	)
Natural gas basis swap - 10,000 Mmbtu/d	Apr-Oct 2006		$	0.85	$	703
Natural gas basis swap - 4,000 Mmbtu/d	Apr-Oct 2006		$	1.07	$	96
Natural gas basis swap - 4,000 Mmbtu/d	Apr-Oct 2006		$	1.04	$	(87	)
					$	(1,194	)

		Total MarkWest Energy Partners			$	(1,027	)

The impact of MarkWest Energy’s commodity derivative instruments on results of operations and financial position are summarized below:

	Three months ended March 31,
	2006			2005
Realized gains – revenue	$	539		$	42
Unrealized gains (losses) – revenue	(299		)	51
Other comprehensive income – changes in fair value	—			(191		)
Other comprehensive income - settlement	—			42

	March 31,
	2006		2005
Unrealized gains – current asset	$	—	$	9
Unrealized losses – current liability	1,027		450

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Siloam Kentucky gas processing and fractionation plant and a dispute as to the monetary value of work and additional work beyond the contract’s lump sum price performed by the contractor. This lawsuit involved a claim of approximately $0.7 million in extra costs. The Company was recently granted Summary Judgment on its defense asserting accord and satisfaction. In August 2005, Plaintiffs filed an appeal of the Summary Judgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that, while it is not able to predict the outcome of this matter, based on the judge’s discussion on the grant of the summary judgment and denial of Ross Brothers’ motion for reconsideration, it is probable that the Company will prevail in the appeal. As a result, the Company has not provided for a loss contingency.

The Company has also been involved in an arbitration proceeding captioned Kevin Stowe and Scott Daves v. MarkWest Hydrocarbon, Inc., American Arbitration Association arbitration, Case No. 77 168 Y 0052 05 BEAH, Denver, Colorado, 2005. Claimants filed an arbitration proceeding against the Company seeking further payments out of a dispute and settlement over interests in certain wells in Colorado. In February 2006, the Arbitrator in the action granted MarkWest’s motion for summary judgment and the arbitration action was dismissed with prejudice.

Item 6. Exhibits

10.30		First amended and restated credit agreement dated as of January 31, 2006, among MarkWest Hydrocarbon, Inc., as borrower, Royal Bank of Canada, as Administrative Agent for the Lenders, Royal Bank of Canada, U.S. Bank National Association and Bank of Oklahoma, N.A., as lenders.(1)

10.30.1		Amendment No. 1 to the first amended and restated credit agreement dated as of March 23, 2006, among MarkWest Hydrocarbon, Inc., as borrower, Royal Bank of Canada, as Administrative Agent for the Lenders, Royal Bank of Canada, U.S. Bank National Association and Bank of Oklahoma, N.A., as lenders.(2)

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, Inc.'s Current Report on Form 8-K, filed with the Commission on February 6, 2006.

(2) Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Current Report on Form 8-K, filed with the Commission on March 29, 2006.

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

Bbl/d		barrels of oil per day
Btu		British thermal units, an energy measurement
Gal/d		gallons per day
Mcf		thousand cubic feet of natural gas
Mcf/d		thousand cubic feet of natural gas per day
MMBtu		million British thermal units, an energy measurement
MMcf		million cubic feet of natural gas
MMcf/d		million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)		revenues less purchased product costs
NGL		natural gas liquids, such as propane, butanes and natural gasoline

		MarkWest Hydrocarbon, Inc.
		(Registrant)

Date: May 8, 2006		/s/ FRANK M. SEMPLE
		Frank M. Semple
		Chief Executive Officer

Date: May 8, 2006		/s/ NANCY K. MASTEN
		Nancy K. Masten
		Senior Vice President and Chief Accounting Officer

6. Derivative Financial Instruments

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

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

Overview

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Item 4. Controls and Procedures

Item 1. Legal Proceedings

SIGNATURES

ý		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

PART I—FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements
	Condensed Consolidated Balance Sheets at March 31, 2006 and December 31, 2005
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2006 and 2005
	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2006 and 2005
	Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2006
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2006 and 2005
	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

SIGNATURE