MARKWEST HYDROCARBON INC - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

		For the quarterly period ended June 30, 2004

		OR

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

		For the transition period from to

		Commission File Number 001-14841

MARKWEST HYDROCARBON, INC.

(Exact name of registrant as specified in its charter)

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

155 Inverness Drive West, Suite 200, Englewood, CO 80112-5000

(Address of principal executive offices)

Registrant’s telephone number, including area code: 303-290-8700

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

Yes ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes o No ý

The registrant had 9,758,674 shares of common stock, $.01 per share par value, outstanding as of July 31, 2004.

PART I—FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements
Consolidated Balance Sheets at June 30, 2004 and December 31, 2003
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2004 and 2003
Consolidated Statements of Other Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2004 and 2003
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003
Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2004
Notes to the 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 4. Submission of Matters to a Vote of Security Holders
Item 6. Exhibits and Reports on Form 8-K

SIGNATURE

Glossary of Terms

Bbl/d		barrels of oil per day
Btu		British thermal units, an energy measurement
Gal/d		gallons per day
Gross margin		revenues less purchased product costs
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
NGL		natural gas liquids, such as propane, butanes and natural gasoline

PART I—FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

MARKWEST HYDROCARBON, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except share and per share data)

	June 30, 2004			December 31, 2003
ASSETS

Current assets:
Cash and cash equivalents	$	33,777		$	42,144
Restricted cash	2,500			2,500
Marketable securities	13,809			—
Receivables, net (including related party receivables of $44 and $40, respectively, and allowance for doubtful accounts of $111 and $120, respectively)	28,300			30,750
Inventories	9,112			4,815
Prepaid replacement natural gas	264			5,940
Deferred income taxes	178			603
Other current assets	415			503
Total current assets	88,355			87,255

Property, plant and equipment	241,088			232,257
Less: accumulated depreciation, depletion, amortization and impairment	(51,188		)	(44,134		)
Total property, plant and equipment, net	189,900			188,123

Other assets:
Intangible assets, net	3,178			3,831
Deferred offering costs	42			1,037
Investment in and advances to equity investee	232			250
Notes receivable from officers	207			217

Total assets	$	281,914		$	280,713

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable (including related party payables of $40 and $51, respectively)	$	31,237		$	24,052
Accrued liabilities	16,863			16,751
Risk management liability	748			1,769
Current portion of long-term debt	86,200			—
Total current liabilities	135,048			42,572

Deferred income taxes	5,105			6,346
Long-term debt	—			126,200
Risk management liability	397			125
Other long-term liabilities	501			504
Non-controlling interest in consolidated subsidiary	94,140			52,782
Commitments and contingencies

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, 9,813,995 and 9,637,977 shares issued, respectively	98			96
Additional paid-in capital	52,259			50,715
Accumulated earnings (deficit)	(3,782		)	3,676
Accumulated other comprehensive loss, net of tax	(1,395		)	(1,793		)
Treasury stock, 68,780 and 75,930 shares, respectively	(457		)	(510		)
Total stockholders’ equity	46,723			52,184

Total liabilities and stockholders’ equity	$	281,914		$	280,713

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

Revenues	$	87,796		$	47,888		$	181,484		$	98,539

Operating expenses:
Purchased product costs	75,451			44,357			150,587			90,360
Facility expenses	5,747			4,417			11,866			8,779
Selling, general and administrative expenses	4,262			3,363			8,746			5,913
Depreciation	3,770			2,041			7,410			3,571
Total operating expenses	89,230			54,178			178,609			108,623

Income (loss) from operations	(1,434		)	(6,290		)	2,875			(10,084		)

Other income (expense):
Interest expense, net	(1,092		)	(1,998		)	(2,450		)	(3,061		)
Non-controlling interest in net income of consolidated subsidiary	(2,549		)	(860		)	(4,242		)	(1,734		)
Other income (expense)	(31		)	105			32			90

Loss before income taxes	(5,106		)	(9,043		)	(3,785		)	(14,789		)

Provision (benefit) for income taxes:
Current	(69		)	(5,875		)	—			(6,045		)
Deferred	(1,827		)	6,931			(1,372		)	4,649
Provision (benefit) for income taxes	(1,896		)	1,056			(1,372		)	(1,396		)

Loss from continuing operations	(3,210		)	(10,099		)	(2,413		)	(13,393		)

Discontinued operations:
Income from discontinued exploration and production operations (net of income taxes of $0, $(705), $0 and $524, respectively)	—			2,377			—			4,658
Gain from disposal of discontinued exploration and production operations, (less applicable income taxes of $1,991)	—			17,701			—			17,701
Income from discontinued operations	—			20,078			—			22,359

Income (loss) before cumulative effect of accounting change	(3,210		)	9,979			(2,413		)	8,966

Cumulative effect of change in accounting for asset retirement obligations, net of tax	—			—			—			(29		)

Net income (loss)	$	(3,210	)	$	9,979		$	(2,413	)	$	8,937

Loss from continuing operations per share:
Basic	$	(0.33	)	$	(1.08	)	$	(0.25	)	$	(1.43	)
Diluted	$	(0.33	)	$	(1.08	)	$	(0.25	)	$	(1.43	)

Net income (loss) per share:
Basic	$	(0.33	)	$	1.07		$	(0.25	)	$	0.96
Diluted	$	(0.33	)	$	1.06		$	(0.25	)	$	0.95

Weighted average number of outstanding shares of common stock:
Basic	9,710			9,351			9,662			9,356
Diluted	9,710			9,371			9,662			9,376

Cash dividend per common share	$	0.025		$	—		$	0.05		$	—

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

Net income (loss)	$	(3,210	)	$	9,979		$	(2,413	)	$	8,937

Other comprehensive income (loss), net of tax:
Foreign currency translation	—			1,797			—			4,061
Risk management activities	(347		)	(131		)	768			(524		)
Marketable securities	(280		)	—			(370		)	—
Total other comprehensive income (loss)	(627		)	1,666			398			3,537

Comprehensive income (loss)	$	(3,837	)	$	11,645		$	(2,015	)	$	12,474

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Six Months Ended June 30,
	2004			2003
Cash flows from operating activities:
Net income (loss)	$	(2,413	)	$	8,937
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of change in accounting	—			29
Depreciation, depletion and amortization	7,410			11,138
Gain from sale of property, plant and equipment	(42		)	—
Amortization of deferred financing costs included in interest expense	627			813
Non-cash compensation expense	344			400
Equity in investee losses	18			—
Non-controlling interest in net income of consolidated subsidiary	4,242			1,735
Derivative ineffectiveness and non-cash mark-to-market adjustment	732			(1,475		)
Reclassification of Enron hedges to purchased gas costs	—			(154		)
Deferred income taxes	(1,372		)	(2,552		)
Gain on sale of San Juan Basin properties	—			(19,692		)
Other	—			237
Changes in operating assets and liabilities:
Decrease in receivables	2,458			10,763
Increase in inventories	(4,297		)	(897		)
Decrease in prepaid	5,676			388
Decrease in other current assets	88			—
Increase in accounts payable and accrued liabilities	7,328			1,910
Net cash flow provided by operating activities	20,799			11,580

Cash flows from investing activities:
Increase in marketable securities	(11,679		)	—
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Hobbs Lateral acquisition	(2,275		)	—
Proceeds from sale of San Juan Basin properties, net of costs to dispose	—			49,470
Capital expenditures	(7,049		)	(14,023		)
Proceeds from sale of assets	195			105
Proceeds from sale of assets to related parties	—			229
Other	8			—
Net cash used in investing activities	(20,800		)	(2,457		)

Cash flows from financing activities:
Proceeds from long-term debt	3,000			68,235
Repayment of long-term debt	(43,000		)	(56,424		)
Debt issuance costs	—			(809		)
Proceeds from MarkWest Energy Partners’ secondary public offering	44,103			—
Proceeds from private placement of MarkWest Energy Partners’ common units, net	—			7,807
Distribution to MarkWest Energy Partners’ unitholders	(6,210		)	(3,242		)
Acquisition of general partner’s membership interests and MarkWest Energy Partners’ subordinated units from related parties	(147		)	—
Exercise of stock options	1,380			167
Net issuance (buyback) of treasury shares	53			(70		)
Payment of dividends	(5,045		)	—
Net cash provided by (used in) financing activities	(5,866		)	15,664
Effect of exchange rate on changes in cash	—			105
Net increase (decrease) in cash and cash equivalents	(5,867		)	24,892
Cash and cash equivalents at beginning of period	42,144			6,410
Cash and cash equivalents at end of period	$	36,277		$	31,302

Supplemental cash flow information:
Cash paid for interest	$	2,077		$	709

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENT OF CHANGES IN

STOCKHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)

	Shares of Common Stock	Shares of Treasury Stock		Common Stock		Additional Paid-In Capital		Accumulated Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity

Balance, December 31, 2003	9,638	(76	)	$	96	$	50,715	$	3,676		$	(1,793	)	$	(510	)	$	52,184

Stock option exercises	176	—		2		1,544		—			—			—			1,546

Dividends	—	—		—		—		(5,045		)	—			—			(5,045		)

Net loss	—	—		—		—		(2,413		)	—			—			(2,413		)

Other comprehensive income	—	—		—		—		—			398			—			398

Net treasury stock reissuances	—	7		—		—		—			—			53			53

Balance, June 30, 2004	9,814	(69	)	$	98	$	52,259	$	(3,782	)	$	(1,395	)	$	(457	)	$	46,723

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

MARKWEST HYDROCARBON, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. General

MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon”, “we”, “us”, “our” or the “Company”) manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), a publicly traded master limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids (NGLs); and the gathering and transportation of crude oil. We also market natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, and the Southwest.

Our assets consist primarily of partnership interests in MarkWest Energy Partners. As of June 30, 2004, our partnership interests consisted of 2,469,496 subordinated units, representing a 34.6% limited partner interest in the Partnership and a 90.2% membership (ownership) interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership. As of July 30, 2004, after the common unit offering (see Note 3), we owned a 29.2% limited partner interest in the Partnership. Our ownership interest in the general partner remained unchanged as of July 30, 2004.

The consolidated financial statements include the accounts of MarkWest Hydrocarbon and its subsidiaries, including MarkWest Energy Partners. Through consolidation, we have eliminated all significant intercompany accounts and transactions. We have reclassified certain prior period amounts to conform to the current year’s presentation.

We have prepared the unaudited financial statements presented herein in accordance with the instructions to Form 10-Q. The statements do not include all the information and note disclosures required by generally accepted accounting principles for complete financial statements. Please read the interim consolidated financial statements in conjunction with the Consolidated Financial Statements and attached notes for the year ended December 31, 2003, included in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission. In the opinion of management, we have made all necessary adjustments for a fair statement of the results for the unaudited interim periods. All said adjustments are of a recurring nature.

We base the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate.

2. Marketable Securities

Marketable securities are classified as available-for-sale and stated at market based on the closing price of the securities at the balance sheet date. Accordingly, unrealized gains or temporary losses are reflected in other comprehensive income (loss), net of applicable income taxes. For losses that are other than temporary, the cost basis of the securities is written down to fair value and the amount of the write-down is reflected in the statement of operations. The Company utilizes a weighted-average cost basis to compute realized gains and losses. Realized gains and losses, and dividend and interest income, are reflected in earnings.

During the first quarter of 2004, the Company funded a $5.0 million brokerage account to invest primarily in equity securities of other Master Limited Partnerships. As of June 30, 2004, approximately $4.9 million had been invested in securities, with the remaining $0.1 million held in cash.

In addition to equity securities, the Company invested approximately $9.3 million in Fannie Mae and Freddie Mac callable debt securities, with interest rates ranging from 2.75% to 4.25%, and maturities ranging from May 2006 through November 2009. These debt securities are reflected in marketable securities.

Debt and equity securities were acquired to provide both capital gains and investment income, and are classified as available-for-sale. The following is a summary of gross unrealized gains and losses:

	June 30, 2004
	(in thousands)
Gross unrealized gains	$	27
Gross unrealized losses	(397		)

Net unrealized losses	$	(370	)

3. Subsequent Event - MarkWest Energy Partners’ Acquisition

On July 30, 2004, the Partnership completed the acquisition (the “American Central East Texas Acquisition”) of American Central East Texas Gas Company. L.P.’s (“American Central”) Carthage gathering system and gas processing assets located in east Texas for approximately $240 million.

The Carthage gathering system has been constructed over the last 10 years and offers both low- and high-pressure service to producers in the Carthage Field, gathering gas from the Cotton Valley, Pettit and Travis Peak formations. The system consists of approximately 180 miles of pipeline connected to approximately 1,700 wells with an additional 82 miles of pipeline currently under construction. The gathering system also includes approximately 65,000 horsepower of compression with an additional 35,000 horsepower currently being installed. Current system throughput is approximately 245 MMcf/d and is anticipated to increase to approximately 310 MMcf/d by the end of 2004 due to the connection to the system of additional contracted volumes. The gathering system has a capacity of approximately 350 MMcf/d. Also included in the acquisition is a 175 MMcf/d processing facility currently under construction and an NGL pipeline to be constructed in 2005.

In conjunction with the closing of the acquisition, the Partnership completed an offering of approximately 1.3 million of its common units, at $34.50 per unit, which netted the Partnership approximately $45 million after transaction costs and the general partner contribution. In addition, the Partnership amended and restated its credit facility, increasing its maximum lending limit from $140 million to $315 million. The credit facility includes a $265 million revolving facility and a $50 million term loan facility. The Partnership used the proceeds from the offering and borrowing under our amended and restated credit facility to finance the American Central East Texas Acquisition. All of the Partnership’s assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowing under the credit facility. The term loan portion of the credit facility matures in December 2004 and the revolving portion matures in May 2005. Consequently, as of June 30, 2004, we have reclassified the Partnership’s debt from non-current liabilities to current liabilities.

4. MarkWest Energy Partners’ Acquisitions

Pinnacle Acquisition

On March 28, 2003, the Partnership completed the acquisition (the “Pinnacle Acquisition”) of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, “Pinnacle” or the “Sellers”). Pinnacle’s results of operations have been included in the Partnership’s consolidated financial statements since that date.

The Pinnacle Acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of the Partnership as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the Partnership entities, and all entities survived the merger. The assets acquired from the Sellers, primarily located in the State of Texas, with the balance located in New Mexico, Louisiana, Mississippi and Kansas, were comprised of three lateral natural gas pipelines and twenty gathering systems.

The purchase price was allocated as follows (in thousands):

Acquisition costs:
Long-term debt incurred	$	39,471
Direct acquisition costs	450
Current liabilities assumed	8,945
Total	$	48,866

Allocation of acquisition costs:
Current assets	$	10,643
Fixed assets (including long-term contracts)	38,223
Total	$	48,866

Western Oklahoma Acquisition

On December 1, 2003, the Partnership completed the acquisition of certain assets of American Central Western Oklahoma Gas Company, L.L.C. (“AWOC”) for approximately $38.0 million, before transaction costs and subject to certain post-closing adjustments. Results of operations for the acquired assets have been included in the Partnership’s consolidated financial statements since that date.

The assets include the Foss Lake gathering system located in the western Oklahoma counties of Roger Mills and Custer. The gathering system is comprised of approximately 167 miles of pipeline, connected to approximately 270 wells, and 11,000 horsepower of compression facilities. The assets also include the Arapaho gas processing plant that was installed during 2000.

The purchase price of approximately $38.0 million was financed through borrowings under the Partnership line of credit, which was amended at the closing of the acquisition to increase availability under the credit facility from $75.0 million to $140.0 million. Substantially all of the acquired assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowings under the credit facility.

The purchase price was comprised of $38.0 million paid in cash to AWOC, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	37,850
Direct acquisition costs	101
Total	$	37,951
Allocation of acquisition costs:
Property, plant and equipment	$	37,951

Michigan Crude Pipeline

On December 18, 2003, the Partnership completed the acquisition (the “Michigan Crude Pipeline acquisition”) of Shell Pipeline Company, LP’s and Equilon Enterprises, LLC’s, doing business as Shell Oil Products US (“Shell”), Michigan Crude Gathering Pipeline (the “System”), for approximately $21.3 million. The System’s results of operations have been included in the Partnership’s consolidated financial statements since December 18, 2003. The $21.3 million purchase price was financed through borrowings under the Partnership’s line of credit.

The System extends from production facilities near Manistee, Michigan to a storage facility near Lewiston, Michigan. The trunk line consists of approximately 150 miles of pipe. Crude oil is gathered into the System from 57 injection points, including 52 central production facilities. The System also includes truck-unloading stations at Manistee, Seeley Road and Junction, and the Samaria Truck Unloading Station located in Monroe County, Michigan, near Toledo, Ohio.

The System is a common carrier Michigan intrastate pipeline and gathers light crude oil from wells. The oil is transported for a fee to the Lewiston, Michigan station where it is batch injected into the Enbridge Lakehead Pipeline.

The purchase price was comprised of $21.3 million paid in cash to Shell, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	21,155
Direct acquisition costs	128
Total	$	21,283

Allocation of acquisition costs:
Property, plant and equipment	$	21,283

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable period presented, as though the Pinnacle Acquisition, the Western Oklahoma acquisition and Michigan Crude Pipeline acquisition each had occurred on January 1, 2003. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Three Months Ended June 30, 2003		Six Months Ended June 30, 2003
	(in thousands, except per share data)
Revenue	$	58,967	$	139,598
Net income	$	9,489	$	8,774
Basic net income per share	$	1.01	$	0.94
Diluted net income per share	$	1.01	$	0.94

5. Property, Plant and Equipment

The following provides composition of our property, plant and equipment at:

	June 30, 2004			December 31, 2003
	(in thousands)
Property, plant and equipment:
Gas gathering facilities	$	82,570		$	73,424
Gas processing plants	56,322			55,888
Fractionation and storage facilities	22,524			22,160
Natural gas pipelines	38,848			38,790
Crude oil pipeline	18,460			18,352
NGL transportation facilities	4,415			4,415
Marketing assets	1,606			1,987
Oil and gas properties and equipment, full cost method	2,499			2,380
Land, buildings and other equipment	10,716			12,499
Construction in-progress	3,128			2,362
	241,088			232,257

Less:Accumulated depreciation, depletion, amortization and impairment	(51,188		)	(44,134		)
Total property, plant and equipment, net	$	189,900		$	188,123

6. Adoption of SFAS No. 143

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. During the first quarter of 2003, we recorded a net-of-tax cumulative effect of change in accounting principle charge of $29,000 ($63,000 before tax), and an asset retirement obligation of $3.2 million (a net increase to long-term liabilities of $2.5 million). We also increased net properties $2.4 million in accordance with the provisions of SFAS No. 143. There was no impact on our cash flows as a result of adopting SFAS No. 143. The asset retirement obligation, which is included in our consolidated balance sheet in other long-term liabilities, was $0.5 million and $3.3 million at June 30, 2004 and 2003, respectively.

7. MarkWest Energy Partners’ Common Unit Offerings

During January 2004, the Partnership completed an offering of 1,100,444 common units at $39.90 per unit for gross proceeds of $43.9 million. In addition, of the 172,200 common units available to underwriters to cover over-allotments, 72,500 were sold for gross proceeds of $2.9 million. To maintain its 2% interest, the general partner of the Partnership contributed $1.0 million, of which $0.1 million was from directors and officers of the general partner. Gross proceeds from parties other than MarkWest Hydrocarbon of $46.9 million less associated offering costs of $3.8 million resulted in net proceeds from the secondary public offering of $43.1 million. As approximately $1.0 million of the offering costs had been incurred during fiscal 2003, net cash generated from the offering during 2004 was approximately $44.1 million.

During July 2004, the Partnership completed an additional offering of its common units. See Note 3.

8. Segment Reporting

Our operations are classified into two reportable segments:

(1) Managing MarkWest Energy Partners—we operate MarkWest Energy Partners, a publicly traded master limited partnership 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.

(2) Marketing—we sell our equity and third-party NGLs, purchase third-party natural gas and sell our equity and third-party natural gas.

During 2003, we discontinued our exploration and production business segment. Our continuing operations are conducted solely in the United States.

The table below presents information about operating income (loss) for the reported segments for the three and six months ended June 30, 2004 and 2003. Segment operating income (loss) includes total revenues less purchased product costs, facility expenses and depreciation. Items excluded from segment operating income (loss) are reflected in the reconciliation of total segment operating income (loss) to income (loss) from continuing operations before taxes. We have not reported asset information by reportable segment because we do not produce such information internally.

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Three Months Ended June 30, 2004:
Revenues from external customers	$	37,170		$	50,626	$	—		$	87,796
Intersegment revenues	$	114		$	13,805	$	(13,919	)	$	—
Segment operating income (loss)	$	(4,532	)	$	7,360	$	—		$	2,828

Three Months Ended June 30, 2003:
Revenues from external customers	$	28,334		$	19,554	$	—		$	47,888
Intersegment revenues	$	178		$	10,082	$	(10,260	)	$	—
Segment operating income (loss)	$	(7,113	)	$	4,186	$	—		$	(2,927	)

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Six Months Ended June 30, 2004:
Revenues from external customers	$	81,339		$	100,145	$	—		$	181,484
Intersegment revenues	$	338		$	28,099	$	(28,437	)	$	—
Segment operating income (loss)	$	(2,471	)	$	14,092	$	—		$	11,621

Six Months Ended June 30, 2003:
Revenues from external customers	$	74,686		$	23,853	$	—		$	98,539
Intersegment revenues	$	445		$	23,476	$	(23,921	)	$	—
Segment operating income (loss)	$	(11,976	)	$	7,805	$	—		$	(4,171	)

A reconciliation of total segment operating income (loss) to loss from continuing operations before taxes is as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(in thousands)
Segment operating income (loss)	$	2,828		$	(2,927	)	$	11,621		$	(4,171	)
Selling, general and administrative expenses	(4,262		)	(3,363		)	(8,746		)	(5,913		)
Interest expense, net	(1,092		)	(1,998		)	(2,450		)	(3,061		)
Non-controlling interest in net income of consolidated subsidiary	(2,549		)	(860		)	(4,242		)	(1,734		)
Other income (expense)	(31		)	105			32			90
Loss from continuing operations before income taxes	$	(5,106	)	$	(9,043	)	$	(3,785	)	$	(14,789	)

9. Commitments and Contingencies

We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on our financial position or results of operations.

10. Stock and Unit Compensation

As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, and SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, we have elected to continue to measure compensation costs for stock-based and unit-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We have two fixed compensation plans and, through our consolidated subsidiary, MarkWest Energy Partners, we have a variable plan. We account for these plans using fixed and variable accounting as appropriate under APB 25.

Had compensation cost for our two stock-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. 123, our net income (loss) and net income (loss) per share would have been revised to the pro forma amounts listed below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(in thousands, except per share data)
Net income (loss), as reported	$	(3,210	)	$	9,979		$	(2,413	)	$	8,937
Add: compensation expense (benefit) included in reported net income (loss)	(30		)	188			344			400
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	8			(299		)	(399		)	(584		)
Pro forma net income (loss)	$	(3,232	)	$	9,868		$	(2,468	)	$	8,753

Net income (loss) per share:
Basic:
As reported	$	(0.33	)	$	1.07		$	(0.25	)	$	0.96
Pro forma	$	(0.33	)	$	1.05		$	(0.26	)	$	0.94
Diluted:
As reported	$	(0.33	)	$	1.06		$	(0.25	)	$	0.96
Pro forma	$	(0.33	)	$	1.05		$	(0.26	)	$	0.93

Compensation expense for the variable plan, including restricted unit grants, is measured using the market price of MarkWest Energy Partners’ common units on the date the number of units in the grant becomes determinable and is amortized into earnings over the period of service. Our stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date.

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

Management Overview of the Three and Six Months Ended June 30, 2004

We reported a net loss for the three months ended June 30, 2004 of $3.2 million, or $0.33 per diluted share, compared to net income of $10.0 million, or $1.06 per diluted share, for the second quarter of 2003. For the six months ended June 30, 2004, the Company reported a net loss of $2.4 million, or $0.25 per diluted share, compared to net income of $8.9 million, or $0.95 per diluted share, for the six months ended June 30, 2003.

The decrease in results from 2003 to 2004 primarily relates to the sale of most of the Company’s San Juan Basin properties on June 30, 2003 for a pretax gain of $19.7 million.

The Company reported a net loss from continuing operations of $3.2 million, or $0.33 per diluted share, for the three months ended June 30, 2004, compared to a net loss from continuing operations of $10.1 million, or $1.08 per diluted share, for the second quarter of 2003. For the six months ended June 30, 2004, the Company reported a net loss from continuing operations of $2.4 million, or $0.25 per diluted share, compared to a net loss from continuing operations of $13.4 million, or $1.43 per diluted share, for the same period last year.

Second-quarter and year-to-date net income (loss) from continuing operations improved over the comparable prior periods primarily due to the contributions of the Partnership’s 2003 acquisitions.

On July 22, 2004, the board of directors of the Company declared a cash dividend of $0.025 per share of its common stock payable on August 19, 2004 to the stockholders of record as of the close of business on August 5, 2004. Consistent with the board’s objective to maintain a regular quarterly dividend, this is the second consecutive dividend declared in 2004. However, any such future declaration will be dependent upon the financial performance of the Company.

In addition, on July 30, 2004, MarkWest Energy Partners expanded its midstream business by completing the acquisition of American Central East Texas Gas Company, L.P.’s Carthage gathering system and gas processing assets for approximately $240 million. The acquisition was funded with a combination of private equity and interim debt financing. Consistent with its long-term strategy of maintaining a debt-to-total-capital ratio of less than 50%, the Partnership intends in the near term to replace the interim debt financing with additional equity and long-term debt financing. The Carthage gathering system offers both low- and high-pressure service to producers in the Carthage Field, gathering gas from the Cotton Valley, Pettit and Travis Peak formations. The system consists of approximately 180 miles of pipeline connected to approximately 1,700 wells with an additional 82 miles of pipeline currently under construction. The gathering system also includes approximately 65,000 horsepower of compression with an additional 35,000 horsepower currently being installed. Current system through put is approximately 245 MMcf/d and is anticipated to increase to approximately 310 MMcf/d by the end of 2004. The gathering system has a capacity of approximately 350 MMcf/d. This acquisition is expected to generate cash flow from operations of approximately $10.0 million for the Partnership for the balance of 2004.

Our Business

We were founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering in 1996.

We are an energy company primarily focused on increasing shareholder value by growing MarkWest Energy Partners, our consolidated subsidiary and a publicly traded master limited partnership 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. We also market natural gas and natural gas liquids. We discontinued our exploration and production activities during 2003.

Our assets consist primarily of partnership interests in MarkWest Energy Partners. As of June 30, 2004, our partnership interests consisted of the following:

• 2,469,496 subordinated units, representing a 34.6% limited partner interest in the Partnership; and

• A 90.2% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2.0% 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 our relationship with MarkWest Energy Partners;

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

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

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 in exchange 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 generally accepted accounting principles, MarkWest Energy Partners’ financial results are included in our consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation. You should read Note 8 to our Consolidated Financial Statements appearing earlier in this Form 10-Q for further information regarding our two business segments: operating MarkWest Energy Partners and marketing.

As a result of our contracts with MarkWest Energy Partners mentioned above, we are the Partnership’s largest customer, accounting for 22% of its revenues and 43% of its gross margin for the six months ended June 30, 2004. We expect to account for less of MarkWest Energy Partners’ business in the future as it continues to acquire assets and increase its customer and business diversification.

Also at the time of the initial public offering, we entered into an Omnibus Agreement with MarkWest Energy Partners and related parties that governs potential competition and indemnification obligations among the parties.

Through our majority ownership in the Partnership’s general partner, we control and operate MarkWest Energy Partners. Our employees are responsible for conducting the Partnership’s business and operating its assets pursuant to a Services Agreement, which was formalized effective January 1, 2004. We receive $5,000 annually from MarkWest Energy Partners for services provided under the Services Agreement. We also are reimbursed for any reasonable costs incurred in the operation of the Partnership.

Our Contracts

Excluding the revenues and gross margin derived by MarkWest Energy Partners, we generate the majority of our revenues and gross margin from the marketing of NGLs and, to a lesser extent, natural gas. As compensation for providing processing services to our Appalachian producers (we have outsourced these services to MarkWest Energy Partners as discussed below), 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 the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an equivalent Btu content. 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 and, consequently, the operating

margins are favorable under these contracts. In the event natural gas and the cost of processing becomes more expensive on a Btu equivalent basis than NGL products, the cost of keeping the producer “whole” results in operating losses.

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 and gas marketing operations were retained by us and not contributed to MarkWest Energy Partners.

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 may increase the volatility of our marketing results and cash flows. We attempt to mitigate our commodity price risk through our hedging program. Under a hedging strategy implemented approximately two years ago that was based on our then-existing natural gas production and historical pricing data through that point in time, we incurred significant hedging losses. For the six months ended June 30, 2004 and 2003, we lost approximately $2.7 million and $8.2 million, respectively, as a result of that hedging strategy. The last transactions associated with this hedging strategy settled in April 2004. You should read Item 3, “Quantitative and Qualitative Disclosures About Market Risk” for further details about our commodity price risk management program, which is incorporated herein by reference.

MarkWest Energy Partners’ Contracts

The Partnership generates the majority of its revenues and gross margin from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage, and crude oil gathering and transportation. While all of these services constitute midstream energy operations, the Partnership provides its services pursuant to four different types of contracts.

• Fee-based contracts. Under fee-based contracts, 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 MarkWest Energy Partners earns from these contracts is generally directly related to the volume of natural gas, NGLs or crude oil that flows through its systems and facilities and is not directly dependent on commodity prices. In certain cases, the Partnership’s contracts provide for minimum annual payments by our customers. To the extent a sustained decline in commodity prices results in a decline in volumes, however, the Partnership’s revenues from these contracts would be reduced.

• Percent-of-proceeds contracts. Under percent-of-proceeds contracts, MarkWest Energy Partners generally 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. Under these types of contracts, MarkWest Energy Partners’ revenues and gross margins increase as natural gas prices and NGL prices increase, and its revenues and gross margins decrease as natural gas prices and NGL prices decrease.

• Percent-of-index contracts. Under percent-of-index contracts, 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. MarkWest Energy Partners 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. With respect to (1) and (3) above, the gross margins the Partnership realizes under the arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price. Conversely, MarkWest Energy Partners’ gross margins increase during periods of high natural gas prices.

• Keep-whole contracts. Under keep-whole contracts, 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, MarkWest Energy Partners must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the value of this natural gas. Accordingly, under these arrangements, the Partnership’s revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs.

In its current areas of operations, MarkWest Energy Partners has a combination of contract types, and limited keep-whole arrangements. The only keep-whole contracts of MarkWest Energy Partners are associated with the Arapaho processing plant that were assumed as a part of its December 2003 Oklahoma acquisition. At the Arapaho processing plant inlet, the Btu content of the natural gas meets the downstream pipeline specifications, however, MarkWest Energy Partners 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 its 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, the Partnership’s overall keep-whole contract exposure is limited to a portion of the operating costs of the plant.

In many cases, MarkWest Energy Partners provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of its 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 may impact MarkWest Energy Partners’ financial results.

Recent MarkWest Energy Partners Acquisition Activity

In reading the discussion of our historical results of operations, you should be aware of MarkWest Energy Partners’ recent significant acquisitions, which impact the comparability of our results of operations for the periods discussed.

From its initial public offering through June 30, 2004, the Partnership has completed five acquisitions for an aggregate purchase price of approximately $112.3 million. These five acquisitions include:

• The Pinnacle acquisition, which closed on March 28, 2003, for consideration of $38.5 million;

• The Lubbock pipeline acquisition (also known as the Power-Tex Lateral pipeline), which closed September 2, 2003, for consideration of $12.2 million;

• The western Oklahoma acquisition, which closed December 1, 2003, for consideration of $38.0 million;

• The Michigan Crude Pipeline acquisition, which closed December 18, 2003, for consideration of $21.3 million; and

• The Hobbs Lateral acquisition, which closed on April 1, 2004, for consideration of $2.3 million.

The first acquisition closed during the last few days of the first quarter of 2003. Three acquisitions closed during the second half of 2003 and one acquisition closed in the second quarter of 2004. Accordingly, our historical results of operations for the six months ended June 30, 2003, save for three months of activity from the Partnership’s Pinnacle acquisition, do not reflect the impact of these acquisitions on our operations. However, our results of operations for the three and six months ended June 30, 2004, do reflect the impact from the Partnership’s four 2003 acquisitions.

Results of Operations

Operating Data

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Marketing
NGL product sales—Siloam plant (gallons)	35,700,000	30,900,000	87,200,000	84,900,000

MarkWest Energy Partners
Appalachia:
Natural gas processed (Mcf/d)(1)	197,000	189,000	202,000	196,000
NGLs fractionated (Gal/d)	480,000	391,000	469,000	418,000

Michigan:
Natural gas volumes transported (Mcf/d)	12,200	14,500	13,000	14,900
NGL product sales (gallons)	2,390,000	2,917,000	5,103,000	5,859,000
Crude oil transported (Bbl/d)(2)	14,700	—	14,700	—

Southwest:
Gathering system throughput (Mcf/d)(3)	103,900	44,600	100,900		NM
Lateral pipeline throughput (Mcf/d)(4)	119,300	—	74,100	—
NGL product sales (gallons) (5)	8,317,000	—	16,512,000	—

NM – Not meaningful.

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

(2) The Partnership acquired its Michigan Crude Pipeline in December 2003.

(3) Includes volumes from the Partnership’s Pinnacle gathering systems, which were acquired in late March 2003, and its Foss Lake (OK) gathering system, which was acquired in December 2003.

(4) Includes volumes from the Partnership’s Power-Tex Lateral pipeline, which was acquired in September 2003, and our Hobbs Lateral pipeline, which was acquired in April 2004. The Power-Tex and Hobbs Lateral pipelines are the only laterals the Partnership own that produce revenue on a per-unit-of-throughput basis. MarkWest Energy Partners receives a flat fee from the other three lateral pipelines it owned during the first quarter of 2004 and, therefore, the throughput data from these lateral pipelines is excluded from this statistic.

(5) Includes sales from the Partnership’s Arapaho (OK) processing plant, which was acquired in December 2003.

Three Months Ended June 30, 2004 Compared to the Three Months Ended June 30, 2003

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Three Months Ended June 30, 2004:
Revenues	$	37,284		$	64,431	$	(13,919	)	$	87,796

Purchased product costs	35,620			47,560		(7,729		)	75,451
Facility expenses	5,840			6,097		(6,190		)	5,747
Depreciation	356			3,414		—			3,770
Total segment operating expenses	41,816			57,071		(13,919		)	84,968

Segment operating income (loss)	$	(4,532	)	$	7,360	$	—		$	2,828

Three Months Ended June 30, 2003:
Revenues	$	28,512		$	29,636	$	(10,260	)	$	47,888

Purchased product costs	30,585			18,423		(4,651		)	44,357
Facility expenses	4,859			5,167		(5,609		)	4,417
Depreciation	181			1,860		—			2,041
Total segment operating expenses	35,625			25,450		(10,260		)	50,815

Segment operating income (loss)	$	(7,113	)	$	4,186	$	—		$	(2,927	)

	Three Months Ended June 30,
	2004			2003
	(in thousands)
Segment operating income (loss)	$	2,828		$	(2,927	)
Selling, general and administrative	(4,262		)	(3,363		)
Interest expense, net	(1,092		)	(1,998		)
Non-controlling interest in net income of consolidated subsidiary	(2,549		)	(860		)
Other income (expense)	(31		)	105

Loss before income taxes	$	(5,106	)	$	(9,043	)

Marketing. Our marketing segment operating loss was $4.5 million for the three months ended June 30, 2004, compared to $7.1 million for the three months ended June 30, 2003, a decrease of $2.6 million. The decrease is partially attributable to a $1.2 million reduction in our hedging losses. The remainder of the change is primarily attributable to marketing initiatives which maximized storage and other transactional opportunities afforded by a more favorable NGL market environment.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $7.4 million for the three months ended June 30, 2004, compared to $4.2 million for the three months ended June 30, 2003, an increase of $3.2 million, or 76%. The increase is primarily attributable to the Partnership’s 2003 acquisitions.

Selling, general and administrative expenses. Selling, general and administrative expenses were $4.3 million for the three months ended June 30, 2004, compared to $3.4 million for the three months ended June 30, 2003, an increase of $0.9 million, or 27%. The increase is attributable to several factors, including increased back office costs associated with the growth of MarkWest Energy Partners, compliance costs, bonus and profit sharing (bonus was not accrued during the three months ended June 30, 2003), and severance.

Interest expense, net. Interest expense, net was $1.1 million for the three months ended June 30, 2004, compared to $2.0 million for the three months ended June 30, 2003, a decrease of $0.9 million, or 45%. The decrease was principally attributable to a reduction of average outstanding consolidated debt levels. Additionally, we generated

$0.2 million in interest income during the three months ended June 30, 2004, compared to $0 for the three months ended June 30, 2003.

Income from discontinued operations. Income from discontinued operations was $0 for the three months ended June 30, 2004, compared to $20.1 million for the three months ended June 30, 2003, a decrease of $20.1 million. The decrease was a result of the sale of substantially all of our U.S. exploration and production business near the end the second quarter of 2003.

Six Months Ended June 30, 2004, Compared to the Six Months Ended June 30, 2003

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Six Months Ended June 30, 2004:
Revenues	$	81,677		$	128,244	$	(28,437	)	$	181,484

Purchased product costs	71,472			95,060		(15,945		)	150,587
Facility expenses	11,937			12,421		(12,492		)	11,866
Depreciation	739			6,671		—			7,410
Total segment operating expenses	84,148			114,152		(28,437		)	169,863

Segment operating income (loss)	$	(2,471	)	$	14,092	$	—		$	11,621

Six Months Ended June 30, 2003:
Revenues	$	75,131		$	47,329	$	(23,921	)	$	98,539

Purchased product costs	75,795			26,815		(12,250		)	90,360
Facility expenses	10,946			9,504		(11,671		)	8,779
Depreciation	366			3,205		—			3,571
Total segment operating expenses	87,107			39,524		(23,921		)	102,710

Segment operating income (loss)	$	(11,976	)	$	7,805	$	—		$	(4,171	)

	Six Months Ended June 30,
	2004			2003
	(in thousands)
Segment operating income (loss)	$	11,621		$	(4,171	)
Selling, general and administrative	(8,746		)	(5,913		)
Interest expense, net	(2,450		)	(3,061		)
Non-controlling interest in net income of consolidated subsidiary	(4,242		)	(1,734		)
Other income	32			90

Loss before income taxes	$	(3,785	)	$	(14,789	)

Marketing. Our marketing segment operating loss was $2.5 million for the six months ended June 30, 2004, compared to a loss of $12.0 million for the six months ended June 30, 2003, a decrease of $9.5 million, or 80%. Approximately $5.4 million of the change was attributable to a reduction in our hedging losses. The remainder of the change is primarily attributable to marketing initiatives which maximized storage and other transactional opportunities afforded by a more favorable NGL market environment.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $14.1 million for the six months ended June 30, 2004, compared to $7.8 million for the six months ended June 30, 2003, an increase of $6.3 million, or 81%. The increase is primarily attributable to the Partnership’s 2003 acquisitions.

Selling, general and administrative expenses. Selling, general and administrative expenses were $8.7 million for the six months ended June 30, 2004, compared to $5.9 million for the six months ended June 30, 2003, an increase of $2.8 million, or 48%. The increase is attributable to several factors, including increased back office costs associated with the growth of MarkWest Energy Partners, compliance costs, bonus and profit sharing (bonus was not accrued during the six months ended June 30, 2003), and severance.

Interest expense, net. Interest expense, net was $2.5 million for the six months ended June 30, 2004, compared to $3.1 million for the six months ended June 30, 2003, a decrease of $0.6 million, or 20%. The decrease was principally attributable to a reduction of average outstanding consolidated debt levels. Additionally, we generated $0.4 million in interest income during the six months ended June 30, 2004, compared to $0 for the six months ended June 30, 2003.

Income from discontinued operations. Income from discontinued operations was $0 for the six months ended June 30, 2004, compared to $22.4 million for the six months ended June 30, 2003, a decrease of $22.4 million. The decrease was a result of the sale of substantially all of our U.S. exploration and production business near the end the second quarter of 2003.

Liquidity and Capital Resources

During 2003, we discontinued our exploration and production activities and sold all of our related Canadian oil and gas properties and substantially all of our U.S. oil and gas properties. The sales netted us $106.7 million in cash. The proceeds were primarily used to pay off and terminate our existing credit facility in its entirety in December 2003. We also had $33.4 million in unrestricted cash on hand at December 31, 2003, exclusive of MarkWest Energy Partners’ cash on hand. As a result, exclusive of MarkWest Energy Partners’ debt, we had no debt as of June 30, 2004 and December 31, 2003. In February 2004, we disbursed approximately $4.8 million to pay a special one-time dividend of $0.50 per share to our common stockholders. In May 2004, we disbursed approximately $0.2 million to pay the first quarterly dividend of $0.025 per common share to our common shareholders. On July 22, 2004, our board of directors declared a dividend of $0.025 per common share to be paid August 19, 2004, to stockholders of record as of the close of business on August 5, 2004.

Going forward, we expect MarkWest Hydrocarbon’s primary sources of liquidity to be quarterly distributions received from MarkWest Energy Partners and cash flows generated principally from the marketing of natural gas and NGLs.

We own 90.2% of the general partner of MarkWest Energy Partners. The general partner of MarkWest Energy Partners owns a 2% general partner interest and all of the incentive distribution rights in MarkWest Energy Partners. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership upon attainment of target distribution levels. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.55 for that quarter, 23.0% of all cash distributed after each unit has received $0.625 for that quarter and 48.0% of all cash distributed after each unit has received $0.75 for that quarter. For the six months ended June 30, 2004, we received $3.4 million in distributions for our subordinated units, and the general partner received $0.5 million, including $0.4 million representing payments on incentive distribution rights. As the Partnership continues to grow and increase its quarterly distributions per limited partner unit, we expect corresponding increases in our distributions.

Cash flows generated from our marketing operations are subject to volatility primarily in NGLs and natural gas prices. Our cash flows are enhanced in periods when the prices received for NGLs exceed the prices paid for natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia, and are reduced in periods when the prices received for NGLs are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the frac spread and, consequently, the operating margins, are favorable. Periodically, when natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer “whole” can result in operating losses. We, however, cannot predict with any certainty what the pricing environment will be in the future.

We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners, and cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Most of our future capital expenditures are discretionary and minimal in nature. During 2004, we have budgeted $1.7 million for our contribution to the Cobb plant replacement and an additional $0.3 million for other miscellaneous projects. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

In an effort to increase our liquidity, we may seek to establish a bank credit facility and renegotiate certain keep-whole contracts in order to reduce our commodity price risk.

MarkWest Energy Partners

The Partnership expects to finance future acquisitions through a combination of debt and issuance of additional units, as is common practice with master limited partnerships.

The Partnership paid down its debt by approximately $42 million in January 2004 with the proceeds from its January 2004 offering of common units.

During July 2004, the Partnership completed an offering of approximately 1.3 million of its common units, at $34.50 per unit, which netted the Partnership approximately $45 million after transaction costs and the general partner contribution. In addition, the Partnership amended and restated its credit facility in July 2004, increasing its maximum lending limit from $140 million to $315 million. The Partnership used the proceeds from the offering and borrowing under its credit facility to finance the American Central East Texas acquisition.

The credit facility includes a $265 million revolving facility and a $50 million term-loan facility. The term-loan portion of the amended and restated credit facility matures in December 2004 and the revolving-portion matures in May 2005. At August 2, 2004, $287 million was outstanding, and $28 million was available, under the credit facility. The Partnership intends to permanently finance these assets in the near term with additional equity and long-term debt. The goal remains for the Partnership to maintain a debt-to-capital ratio of less than 50 percent in keeping with its long-term balance sheet objectives.

Cash Flows

	Six Months Ended June 30,
	2004			2003
	(in thousands)
Net cash provided by operating activities	$	20,799		$	11,580
Net cash used in investing activities	$	(20,800	)	$	(2,457	)
Net cash provided by (used in) financing activities	$	(5,866	)	$	15,664

Net cash provided by operating activities for the six months ended June 30, 2004, increased relative to the same period in the prior year principally due to an increase in net income (loss) from continuing operations.

Net cash used in investing activities for the six months ended June 30, 2004, increased relative to the same period in the prior year primarily due to the proceeds received in 2003 from the sale of our U.S. exploration and production business.

Net cash used in financing activities for the six months ended June 30, 2004, was primarily attributable to quarterly distributions paid by the Partnership and quarterly dividends paid by the Company. Net cash provided by financing activities for the six months ended June 30, 2003, was primarily attributable to borrowings of long-term debt exceeding repayments of long-term debt.

Forward-Looking Information

Statements included in this Management’s Discussion and Analysis 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,” “plan,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

These forward-looking statements are made based upon management’s current plans, 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 as a result of certain factors as more fully discussed under the heading “Risk Factors” contained in our annual report on Form 10-K filed on March 15, 2004 with the Securities and Exchange Commission (File No. 001-31239) for the Company’s fiscal year ended December 31, 2003. 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. and successfully integrate its acquisitions.

• Our ability to amend certain producer contracts.

• Our expectations regarding natural gas, NGL 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.

• Our ability to secure a credit facility.

• Our ability to refinance the Partnership's outstanding debt.

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

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

• The availability and prices of NGL and competing commodities.

• The availability and prices of raw natural gas supply.

• 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 ability to identify and consummate grass-roots projects or acquisitions complementary to our business.

• Winter weather conditions.

Forward-looking statements involve many uncertainties that are beyond our ability to control. In many cases, we cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements.

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 variations and also incur, to a lesser extent, credit risks and risks related to interest rate variations.

Commodity Price Risk

Through our consolidated subsidiary, MarkWest Energy Partners, L.P., we are engaged in the gathering processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil. We also market natural gas and NGL products. Our products are commodities that are subject to price risk resulting from material changes in response to fluctuations in supply and demand, general economic conditions and other market conditions, such as weather patterns, over which we have no control.

Our primary risk management objective is to reduce volatility in our cash flows. Our hedging approach uses a statistical method that analyzes momentum and average pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. A committee, which includes members of senior management, oversees all of our hedging activity.

We may utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on the over-the-counter (OTC) market. New York Mercantile Exchange (NYMEX) traded futures are authorized for use. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.

We enter 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. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements and NYMEX positions.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs, or crude oil or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.

In addition to these risk management tools, we utilize our NGL product storage facilities and contracts for third-party storage to build product inventories during lower-demand periods for resale during higher-demand periods.

NGL Price Risk

Within our NGL marketing segment, our price risk varies by contract as well as by spot market prices for both NGL and natural gas commodities. Our Appalachian producers compensate us for providing midstream services under one of two contract types:

• Under “keep-whole” contracts, we take title to and sell the NGLs produced in our processing operations. We also reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Keep-whole contracts therefore expose us to NGL product price risk (on the sales side) and natural gas price risk (on the purchase or reimbursement side). Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer “whole” results in operating losses. 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”.

• Under “percent-of-proceeds” contracts, we take title to the NGLs produced in our processing operations, sell the NGLs to third parties and pay the producer a specified percentage of the proceeds received from the sales. Percent-of-proceeds contracts therefore expose us to NGL product price risk. All of our Michigan processing business is also governed by percent-of-proceeds contracts.

Our consolidated subsidiary, MarkWest Energy Partners, is also subject to NGL price risk. For the six months ended June 30, 2004, approximately 31% of MarkWest Energy Partners’ business (as measured by gross margin) was directly subject to NGL product price risk stemming from its percent-of-index contracts, percent-of-proceeds contracts and keep-whole contracts. Approximately 9% of MarkWest Energy Partners’ gross margin is governed by keep-whole contracts. The related commodity price risk exposure is actively managed, to the extent possible, by not operating the Arapaho processing plant in Oklahoma during low processing margin environments.

As of June 30, 2004, we had no contracts in place to manage our NGL product price risk.

Natural Gas Price Risk

In response to our natural gas price risk in Texas (as part of MarkWest Energy Partners’ Pinnacle acquisition), we enter into fixed-for-float swaps or buy puts. As of June 30, 2004, we hedged our Texas natural gas price risk via swaps as follows:

	Year Ending December 31,
	2004		2005
MarkWest Energy Partners, L.P.
MMBtu	92,000		182,500
$/MMBtu	$	4.57	$	4.26

As of June 30, 2004, the Partnership hedged its Texas natural gas price risk with puts as follows:

	Year Ending December 31
	2004		2005
MarkWest Energy Partners, L.P.
MMBtu	184,000		—
$/MMBtu	$	4.00	$	—

Interest Rate Risk

MarkWest Energy Partners is exposed to changes in interest rates, primarily as a result of its long-term debt under its credit facility with floating interest rates. The Partnership makes use of interest-rate swap and collar agreements to adjust the ratio of fixed and floating rates (LIBOR plus an applicable margin) in its debt portfolio.

As of June 30, 2004, the Partnership is a party to interest rate swap agreements to fix interest rates on debt of $8.0 million at 3.84% through May 2005 and $25.0 million at 3.33% through November 2006 (currently $33.0 million with a weighted average interest rate of 3.46%). In addition, the Partnership is a party to an interest-rate collar agreement on $20.0 million of debt with a maximum rate of 3.33% through May 2005, and a minimum rate of 1.25% through August 2004, 1.30% through November 2004, 2.10% through February 2005 and 2.60% through May 2005.

Item 4. Controls and Procedures

Attached as exhibits 31.1, 31.2 and 31.3 to this Quarterly Report are certifications of our principal executive and accounting officers (who we refer to in this periodic report as our Certifying Officers) required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002 (the “Section 302 Certifications”). This portion of our Quarterly Report on Form 10-Q discloses the results of our evaluation of our disclosure controls and procedures as of June 30, 2004, referred to in paragraphs (4) and (5) of the Section 302 Certifications and should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our Certifying Officers, as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure control and procedures as of June 30, 2004, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of June 30, 2004, our disclosure controls and procedures were effective.

Nevertheless, we are continuing to conduct an internal review under the supervision and with the participation of our management and our Certifying Officers of the effectiveness of the design and operation of our disclosure controls and procedures. The purpose of such review is to identify and establish enhancements to our disclosure controls and procedures that can help prevent any potential misstatements or omissions in our consolidated financial statements. Such enhancements are also focused on assisting our management in evaluating the effectiveness of our internal controls over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002 commencing with our fiscal year ending December 31, 2004.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Reference is made to Note 9 of our Consolidated Financial Statements in Item 1 of this Form 10-Q.

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

The Annual Meeting of Stockholders was held on June 3, 2004. At the Annual Meeting, two individuals were elected as directors of the Company and six individuals continue to serve as directors pursuant to their prior elections. Those directors continuing in office are John M. Fox, Frank M. Semple, Arthur J. Denney, Donald C. Heppermann, Karen L. Rogers and Donald D. Wolf. In addition, the appointment of KPMG LLP as the independent auditor of the Company for 2004 was ratified. A tabulation of the voting at the Annual Meeting with respect to the matters indicated is as follows:

1. To elect two Class II directors to hold office for a three-year term expiring at the Annual Meeting of Stockholders occurring in the year 2007 or until the election and qualification of their respective successors.

	Number of Shares
	For	Withheld
William A. Kellstrom	9,319,165	77,152
William F. Wallace	9,018,452	377,865

2. To ratify the selection of KPMG LLP as our independent auditors for the fiscal year ending December 31, 2004.

		Number of Shares
For		9,363,002
Against		30,665
Abstain		2,650

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

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.

31.3		Certification of the Chief Accounting 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.

32.3		Certification of the Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

A Current Report on Form 8-K/A was furnished with the SEC under Item 4 and Item 7 on April 6, 2004, announcing that the Company’s dismissal of its former independent accountants became effective as of March 30, 2004.

A Current Report on Form 8-K was furnished with the SEC under Item 4 on April 12, 2004, announcing that the Company engaged KPMG LLP as its independent accountants for the fiscal year ending December 31, 2004.

A Current Report on Form 8-K was furnished with the SEC under Item 12 on May 6, 2004, concerning the Company’s first quarter earnings release dated May 6, 2004.

A Current Report on Form 8-K was furnished with the SEC under Item 9 on June 2, 2004, announcing the appointment of James G. Ivey as Chief Financial Officer of MarkWest Hydrocarbon, Inc.

SIGNATURE

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

		MarkWest Hydrocarbon, Inc.
		(Registrant)

Date: August 11, 2004		/s/ JAMES G. IVEY
		James G. Ivey
		Chief Financial Officer

Exhibit Number		Exhibit Index

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.

31.3		Certification of the Chief Accounting 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.

32.3		Certification of the Chief Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.