UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2006

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	(IRS Employer
incorporation or organization)	Identification No.)

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

 (Address of principal executive offices)

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

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

Yes  x    No  o

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

Large accelerated filer    o Accelerated filer    x Non-accelerated filer    o

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

Yes  o    No  x

The registrant had 11,958,758 shares of common stock, $0.01 per share par value, outstanding as of October 18, 2006.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2006 and 2005
	Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2006 and 2005
	Condensed Consolidated Statement of Changes in Stockholders’ Equity for the nine months ended September 30, 2006
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 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

Glossary of Terms

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
MMBtu/d	million British thermal units of natural gas per day
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

2

PART I–FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited, in thousands, except share data)

	September 30, 2006			December 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	36,800		$	20,968
Marketable securities	7,056			6,070
Receivables, net of allowances of $220 and $175, respectively	94,077			145,539
Inventories	46,299			41,067
Fair value of derivative instruments	10,276			—
Other current assets	13,421			16,314
Total current assets	207,929			229,958
Property, plant and equipment	618,322			573,198
Less: accumulated depreciation, depletion, amortization and impairment	(100,563		)	(78,500		)
Total property, plant and equipment, net	517,759			494,698
Other assets:
Investment in Starfish	59,596			39,167
Intangible assets, net	335,411			346,496
Deferred financing costs, net of accumulated amortization of $5,079 and $4,442, respectively	16,741			18,463
Deferred contract cost, net of accumulated amortization of $624 and $390, respectively	2,626			2,860
Investment in and advances to other equity investee	—			182
Fair value of derivative instruments	3,236			—
Notes receivable from related parties	106			154
Other long term assets	1,158			326
Total other assets	418,874			407,648
Total assets	$	1,144,562		$	1,132,304
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable (including related party payables of $0 and $25, respectively)	$	101,043		$	119,105
Accrued liabilities	41,422			45,869
Fair value of derivative instruments	3,401			728
Deferred income taxes	627			362
Current portion of long term debt	—			2,738
Total current liabilities	146,493			168,802
Deferred income taxes	6,488			3,487
Fair value of derivative instruments	522			—
Long-term debt, net of original issue discount of $3,217 and $0, respectively	479,654			608,762
Non-controlling interest in consolidated subsidiary	443,306			301,015
Other long-term liabilities	22,704			10,256
Total liabilities	1,099,167			1,092,322
Commitments and contingencies (Note 11)
Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding	—			—
Common stock, par value $0.01, 20,000,000 shares authorized, 11,958,905 and 11,943,733 shares issued, respectively	120			108
Additional paid-in capital	42,209			48,797
Deferred compensation	—			(398		)
Accumulated earnings (deficit)	2,279			(8,425		)
Accumulated other comprehensive income, net of tax	800			357
Treasury stock, 1,332 and 55,619 shares, respectively	(13		)	(457		)
Total stockholders’ equity	45,395			39,982
Total liabilities and stockholders’ equity	$	1,144,562		$	1,132,304

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

3

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share amounts)

	Three months ended September 30,						Nine months ended September 30,
	2006			2005			2006			2005
Revenues:
Revenue	$	183,516		$	171,673		$	610,985		$	451,779
Derivative gain (loss)	22,721			(1,048		)	8,406			(1,761		)
Total revenue	206,237			170,625			619,391			450,018
Operating expenses:
Purchased product costs	108,220			145,876			406,245			362,929
Facility expenses	14,656			12,082			42,577			32,327
Selling, general and administrative expenses	19,069			7,913			43,506			25,140
Depreciation	8,126			5,025			23,282			14,761
Amortization of intangible assets	4,029			2,098			12,072			6,288
Accretion of asset retirement obligations	24			116			75			137
Total operating expenses	154,124			173,110			527,757			441,582
Income (loss) from operations	52,113			(2,485		)	91,634			8,436
Other income (expense):
Earnings (losses) from unconsolidated affiliates	1,067			(999		)	3,240			(9		)
Interest income	264			271			1,106			841
Interest expense	(9,583		)	(4,980		)	(31,425		)	(13,273		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(6,121		)	(557		)	(7,805		)	(1,651		)
Dividend income	112			101			327			289
Miscellaneous income	3,978			65			7,737			300
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	41,830			(8,584		)	64,814			(5,067		)
Income tax benefit (expense)
Current	(3,283		)	—			(2,854		)	—
Deferred	(2,105		)	2,868			(3,001		)	2,900
Income tax benefit (expense)	(5,388		)	2,868			(5,855		)	2,900
Non-controlling interest in net (income) loss of consolidated subsidiary	(26,438		)	28			(48,255		)	(3,591		)
Net income (loss)	$	10,004		$	(5,688	)	$	10,704		$	(5,758	)
Net income (loss) per share:
Basic	$	0.84		$	(0.48	)	$	0.90		$	(0.49	)
Diluted	$	0.83		$	(0.48	)	$	0.89		$	(0.49	)
Weighted average number of outstanding shares of common stock (December 31, 2005 adjusted to reflect May 23, 2006 Stock Dividend, see Note 2):
Basic	11,956			11,872			11,933			11,859
Diluted	12,015			11,872			12,021			11,859
Cash dividend declared per common share	$	0.28		$	0.09		$	0.695		$	0.25

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

4

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)

	Three months ended September 30,					Nine months ended September 30,
	2006		2005			2006		2005
Net income (loss)	$	10,004	$	(5,688	)	$	10,704	$	(5,758	)
Other comprehensive income (loss):
Unrealized gains (losses) on marketable securities, net of tax of $95, $(24), $266 and $92, respectively.	156		(40		)	443		151
Unrealized gains on commodity derivative instruments accounted for as hedges, net of tax of $0, $240, $0 and $118, respectively.	—		392			—		195
Total other comprehensive income	156		352			443		346
Comprehensive income (loss)	$	10,160	$	(5,336	)	$	11,147	$	(5,412	)

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

5

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)			Other Comprehensive Income		Treasury Stock			Total Stockholders’ Equity
Balance, December 31, 2005	10,858	(56	)	$	108	$	48,797		$	(398	)	$	(8,425	)	$	357	$	(457	)	$	39,982
May 23, 2006 Stock Dividend Adjustment (Note 2)	1,085	—		11		(11		)	—			—			—		—			—
Adjusted balance December 31, 2005	11,943	(56	)	119		48,786			(398		)	(8,425		)	357		(457		)	39,982
Stock option exercises	12	20		1		62			—			—			—		160			223
Compensation expense related to equity-based awards		—		—		360			—			—			—		—			360
Issuance of restricted stock	1	34		—		(284		)	—			—			—		284			—
Cashless stock option exercises	3	—		—		—			—			—			—		—			—
Reclassification of unearned compensation related to the adoption of Statement of Financial Accounting Standards No. 123R (Note 2)	—	—		—		(398		)	398			—			—		—			—
Net income	—	—		—		—			—			10,704			—		—			10,704
Dividend	—	—		—		(6,317		)	—			—			—		—			(6,317		)
Other comprehensive income	—	—		—		—			—			—			443		—			443
Balance, September 30, 2006	11,959	(2	)	$	120	$	42,209		$	—		$	2,279		$	800	$	(13	)	$	45,395

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

6

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Nine months ended September 30,
	2006			2005
Cash flows from operating activities:
Net income (loss)	$	10,704		$	(5,758	)
Adjustments to reconcile net income to net cash provided by operating activities (net of acquisitions):
Depreciation	23,282			14,761
Amortization of intangible assets	12,072			6,288
Amortization of deferred financing costs and original issue discount	7,805			1,651
Accretion of asset retirement obligation	75			137
Amortization of gas contract	234			234
Restricted unit compensation expense	1,103			900
Participation Plan compensation expense	12,133			3,610
Stock option compensation expense	45			1,285
Restricted stock compensation expense	315			55
Non-controlling interest in net income of consolidated subsidiary	48,255			3,591
Contribution of treasury shares to 401(k) benefit plan	—			188
Imputed interest on debt securities	—			(11		)
Equity in (earnings) losses of unconsolidated affiliates	(3,240		)	9
Distributions from equity investments	—			1,848
Unrealized gain on derivative instruments	(10,317		)	(739		)
Gain on sale of property, plant and equipment	(330		)	(220		)
Deferred income taxes	3,001			(2,900		)
Gain from sale of marketable securities	—			(56		)
Loss on sale of equity investee	26			—
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	45,144			(10,277		)
Inventories	(5,232		)	(11,557		)
Other assets	2,061			(8,214		)
Accounts payable and accrued liabilities	(17,243		)	28,413
Other long-term liabilities	376			44
Net cash provided by operating activities	130,269			23,282
Cash flows from investing activities:
Additional Javelina acquisition costs	(6,872		)	—
Investment in Starfish	(17,183		)	(41,688		)
Purchase of marketable securities	(789		)	(8,725		)
Proceeds from sale of marketable securities	511			8,536
Capital expenditures	(44,859		)	(50,368		)
Proceeds from sale of equity investee	90			—
Proceeds from sale of property, plant and equipment	519			248
Net cash flows used in investing activities	(68,583		)	(91,997		)
Cash flows from financing activities:
Proceeds from long-term debt	307,500			97,000
Payments of long-term debt	(439,429		)	(11,500		)
Collection of related party notes receivable	48			53
Payments for debt issuance costs deferred financing costs and registration costs	(6,075		)	(5,096		)
Proceeds from MarkWest Energy’s private placement, net	5,000			—
Proceeds from MarkWest Energy’s public offering, net	123,395			—
Exercise of stock options	223			77
Purchase of treasury shares	—			(161		)
Payment of dividends	(6,317		)	(2,965		)
Distributions to MarkWest Energy unitholders	(30,199		)	(19,379		)
Net cash flows provided by (used in) financing activities	(45,854		)	58,029
Net increase (decrease) in cash	15,832			(10,686		)
Cash and cash equivalents at beginning of year	20,968			12,844
Cash and cash equivalents at end of period	$	36,800		$	2,158
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amount capitalized	$	23,245		$	13,009
Cash paid for income taxes	$	1,619		$	549
Supplemental schedule of non-cash investing and financing activities:
Construction projects in progress	$	1,528		$	329

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

7

MARKWEST HYDROCARBON, INC.

NOTES TO 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 where we do not control and are not the primary beneficiary, are accounted for using the equity method.

These condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in 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 nine months ended September 30, 2006, are not necessarily indicative of results for the full year 2006, or any other future period.

On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006. 1,084,647 shares were issued at a fair value of $24.4 million, based upon the last sale price on the record date ($22.50 per share). Cash of $3,200 was paid in lieu of fractional shares, based upon the last sale price on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the dividend of our common stock.

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 Opinion No. 25 (“APB 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 for an estimate of expected award forfeitures.

Under APB 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 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.

8

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 stock option plans are categorized as equity awards, while under APB 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 25 it 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 this 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 have no definite term, but historically have 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 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 and under APB 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 each employee devotes to the Company.  Compensation attributable to interests 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 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 adjusted to the pro forma amounts listed below:

9

	Three months ended September 30, 2005			Nine months ended September 30, 2005
	(in thousands, except per share data)
Net loss, as reported	$	(5,688	)	$	(5,758	)
Add: compensation expense included in reported net income, net of related tax effect	922			3,894
Deduct: total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect	(708		)	(3,050		)
Pro forma loss:	$	(5,474	)	$	(4,914	)
Net loss per share:
Basic:
As reported	$	(0.48	)	$	(0.49	)
Pro forma	$	(0.46	)	$	(0.41	)
Diluted:
As reported	$	(0.48	)	$	(0.49	)
Pro forma	$	(0.46	)	$	(0.41	)

3. Recent Accounting Pronouncements

In February 2006 the Financial Accounting Standards Board (“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 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.

In June 2006 the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a “more likely than not” recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of FIN 48.

In September 2006 the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157”). SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years, with early adoption permitted.  The Company has not yet determined the impact, if any, the implementation of SFAS No. 157 may have on the condensed consolidated financial statements of the Company.

In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB 108 is effective for the first annual period ending after November 15, 2006. The Company is currently evaluating the impact of adopting SAB 108 on its financial statements.

10

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 $41.8 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 completed its purchase price allocation in May 2006, including a final working capital settlement to the seller of $5.9 million.

Starfish Joint Venture

On March 31, 2005, the Partnership paid $41.7 million to an affiliate of Enterprise Products Partners L.P. for a 50% non-operating membership interest in Starfish Pipeline Company, LLC, (“Starfish”).  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 interest in Starfish. Summarized financial information for 100% of Starfish is as follows:

	Three months ended September 30,				Nine months ended September 30,
	2006		2005		2006		2005
	(in thousands)
Revenues	$	8,907	4,422		$	21,486	15,966
Operating income (loss)	1,979		(1,977	)	5,083		1,899
Net income (loss)	2,289		(1,844	)	6,921		2,181

Pro Forma Results of Operations

The following table reflects the pro forma consolidated results of operations for the three and nine months ended September 30, 2005, as though the Starfish acquisition and the Javelina acquisition had occurred on January 1, 2005.  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 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 September 30, 2005			Nine months ended September 30, 2005
	(in thousands)
Revenue	$	267,939		$	657,299
Net loss	$	(5,778	)	$	(8,382	)
Net loss per share
Basic	$	(0.49	)	$	(0.71	)
Diluted	$	(0.49	)	$	(0.71	)
Weighted average number of outstanding shares of common stock:
Basic	11,872			11,859
Diluted	11,872			11,859

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5. Other Long-Term Assets

	September 30, 2006		December 31, 2005
	(in thousands)
Risk management premium	$	832	$	—
Other	326		326
	$	1,158	$	326

Risk management premium

In the third quarter of 2006 the Partnership entered into certain put option contracts on commodities requiring premium payments to secure certain floor prices.  The Partnership paid $0.8 million to the counterparty as a premium on certain long-term put option contracts.  The payment is recorded as a long-term asset (and reclassified to a current asset once the contract is set to expire within one year) and will be amortized through revenue as the puts expire or are exercised.  The contracts are recorded as derivative instruments, so changes in fair value of the contracts are recorded as an unrealized gain or loss.

6. Debt

	September 30, 2006		December 31, 2005
	(in thousands)
MarkWest Hydrocarbon Credit Facility
Revolver facility, 8.75% interest at December 31, 2005, due August 2009	$	—	$	7,500
Partnership Credit Facility
Term loan, 8.75% interest at December 31, 2005, due December 2010	45,872		365,000
Revolver facility, 8.75% interest at December 31, 2005, due December 2010	12,000		14,000
Partnership Senior Notes
Senior Notes, 6.875% interest, due November 2014	225,000		225,000
Senior Notes, 8.5% interest, net of original issue discount of $3,217, due July 2016	196,782		—
	479,654		611,500
Less: obligations due in one year	—		(2,738		)
Total long-term debt	$	479,654	$	608,762

MarkWest Hydrocarbon

Credit Facility (August 2006 to Present)

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

The Company Credit Facility bears interest at a variable interest rate, plus basis points.  The variable interest rate typically is based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate.  The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75% for Eurodollar Rate loans.  The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.

Under the provisions of the Company Credit Facility, the Company is subject to a number of restrictions on its business, including its ability to grant liens on assets; make or own certain investments; enter into any swap contracts other

12

than in the ordinary course of business; merge, consolidate or sell assets; incur indebtedness (other than subordinated indebtedness); make distributions on equity investments; declare or make, directly or indirectly, any restricted distributions.

The credit facility also contains covenants requiring the Company to maintain:

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

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

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

Credit Facility (January 2006 to August 2006)

On January 31, 2006, the Company entered into the first amended and restated credit agreement, which provided a maximum lending limit of $25.0 million for a one-year term, and which amended and restated the October 2004 agreement discussed below. As of September 30, 2006, the Company had $6.0 million of the availability committed to a letter of credit, leaving $19.0 million available for revolving loans.

On March 23, 2006, the Company amended the First Amended and Restated Credit Agreement to reduce the cash reserve requirement from $13.0 million to $5.0 million through December 31, 2006.

Credit Facility (October 2004 to January 2006)

In October 2004 the Company entered into a $25.0 million senior credit facility with a term of one year.  The $25.0 million revolving facility had a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus ½ of 1%, and b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage.  In October, November and December 2005, the Company entered into the first, second and third amendment to the credit agreement.  The first amendment extended the term of the original agreement to November 15, 2005.  The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving $10.0 million available for revolving loans.  The second amendment also extended the term of the revolving credit to December 30, 2005.  The third amendment extended the term of the revolving credit to January 31, 2006, and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving $7.5 million available for revolving loans at December 31, 2005.

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 typically is based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5 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”). For the three and nine months ended September 30, 2006, the weighted average interest rate on the Partnership Credit Facility was 7.74% and 7.19%.

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2016 Senior Notes

In July 2006 the Partnership and its subsidiary MarkWest Energy Finance Corporation completed their private placement of $200 million in aggregate principal amount of 8.5% senior notes due 2016 (the “2016 Senior Notes”) to qualified institutional buyers. The 2016 Senior Notes will mature on July 15, 2016, and interest is payable on each July 15 and January 15, commencing January 15, 2007. The net proceeds from the private placement were approximately $191.2 million, after deducting the initial purchasers’ discounts and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering to repay a portion of the term debt under the Partnership Credit Facility. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc., and Wachovia Capital Markets, LLC, are lenders under the Partnership Credit Facility.  MarkWest Energy Partners, L.P. has no independent assets or operations.  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.  These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership’s obligations in respect of its Partnership Credit Facility.

The indenture governing the Partnership’s 2016 Senior Notes limits the activity of the Partnership and its restricted subsidiaries, including 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 2016 Senior Notes.  If the Partnership fails to complete the exchange offer in the time provided for in the subscription agreements (January 6, 2007), it will begin 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. Amendment No. 1 to the S-4 registration statement was filed on October 3, 2006, and has not yet been declared effective.

2014 Senior Notes

In October 2004 the Partnership and its subsidiary, MarkWest Energy Finance Corporation, issued $225.0 million in senior notes (“2014 Senior Notes”) at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, and 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) experiences specific kinds of changes in control.  MarkWest Energy Partners, L.P. has no independent assets or operations.  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.  These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership’s obligations in respect of its Partnership Credit Facility.

The indenture governing the 2014 Senior Notes limits the activity 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

14

registration statement, pursuant to a registration rights agreement relating to the 2014 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, was 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 was completed. The registration statement was filed on January 17, 2006, the exchange offer was completed on March 7, 2006, and the interest penalty ceased.

7. Derivative Financial Instruments

Commodity Instruments

MarkWest Hydrocarbon and MarkWest Energy 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 enters into 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 engages in derivative activities, they may be prevented from realizing the benefits of favorable price changes in the physical market; however, it may be similarly insulated against unfavorable changes.

Both the Company and the Partnership have a committee comprised of the senior management team that oversees all of the risk management activity and the use of derivative instruments.

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

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

The following tables summarize the derivative positions specific to MarkWest Hydrocarbon’s Standalone segment at September 30, 2006:

Swaps	Contract  Period	Fixed Price (1)		Fair Value
				(in thousands)
Crude Oil - 642 Bbl/d	Apr-Jun 2007	$	67.00	$	(55	)
Crude Oil - 313 Bbl/d	Apr-Jun 2007	80.21		336
Iso Butane - 6,532 Gal/d	Oct 2006	1.12		(14		)
Iso Butane - 6,750 Gal/d	Nov 2006	1.12		(18		)
Iso Butane - 8,492 Gal/d	Dec 2006	1.12		(21		)
Iso Butane - 2,503 Gal/d	Dec 2006	1.34		11
Iso Butane - 2,371 Gal/d	Jan 2007	1.35		10
Iso Butane - 6,184 Gal/d	Jan-Mar 2007	1.16		(28		)
Iso Butane - 3,007 Gal/d	Feb-Mar 2007	1.35		24
Iso Butane - 1,806 Gal/d	Mar 2007	1.28		4
Natural Gasoline - 13,065 Gal/d	Oct 2006	1.39		19
Natural Gasoline - 13,500 Gal/d	Nov 2006	1.39		11

15

Natural Gasoline - 8,492 Gal/d	Dec 2006	1.37	(4		)
Natural Gasoline - 16,647 Gal/d	Dec 2006	1.50	56
Natural Gasoline - 8,419 Gal/d	Jan 2007	1.59	43
Natural Gasoline - 12,446 Gal/d	Jan-Mar 2007	1.37	(63		)
Natural Gasoline - 10,034 Gal/d	Feb-Mar 2007	1.59	94
Natural Gasoline - 4,387 Gal/d	Mar 2007	1.62	26
Normal Butane - 19,597 Gal/d	Oct 2006	1.10	(19		)
Normal Butane - 20,250 Gal/d	Nov 2006	1.10	(30		)
Normal Butane - 25,476 Gal/d	Dec 2006	1.10	(38		)
Normal Butane - 10,281 Gal/d	Dec 2006	1.30	48
Normal Butane - 8,639 Gal/d	Jan 2007	1.29	33
Normal Butane - 18,891 Gal/d	Jan-Mar 2007	1.13	(42		)
Normal Butane - 10,712 Gal/d	Feb-Mar 2007	1.29	83
Normal Butane - 5,839 Gal/d	Mar 2007	1.28	23
Propane - 62,710 Gal/d	Oct 2006	0.93	(47		)
Propane - 13,548 Gal/d	Oct 2006	1.10	63
Propane - 64,800 Gal/d	Nov 2006	0.93	(74		)
Propane - 23,667 Gal/d	Nov 2006	1.09	89
Propane - 3,500 Gal/d	Nov 06-Feb 07	1.05	31
Propane - 81,523 Gal/d	Dec 2006	0.93	(104		)
Propane - 174,342 Gal/d	Dec 2006	1.11	755
Propane - 171,226 Gal/d	Jan 2007	1.12	734
Propane - 71,516 Gal/d	Jan-Mar 2007	0.96	(32		)
Propane - 133,429 Gal/d	Feb 2007	1.10	462
Propane - 23,797 Gal/d	Feb-Mar 2007	1.18	288
Propane - 25,806 Gal/d	Mar 2007	1.13	133
			$	2,787

Fixed Physical (Forward Purchases)	Contract  Period	Fixed Price (1)		Fair Value
				(in thousands)
Natural Gas - 9,677 MMBtu/d	Oct 2006	$	7.19	$	(859	)
Natural Gas - 11,000 MMBtu/d	Nov 2006	6.48		(229		)
Natural Gas - 6,371 MMBtu/d	Jan 2007	10.41		448
Natural Gas - 7,143 MMBtu/d	Feb 2007	10.76		505
				$	(135	)
Current-Total MarkWest Hydrocarbon Standalone				$	2,652

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

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

	Three months ended September 30,						Nine months ended September 30,
	2006			2005			2006			2005
Realized losses - revenue	$	(255	)	$	(786	)	$	(255	)	$	(2,086	)
Unrealized gains - revenue	10,306			5			2,652			739
Other comprehensive income - changes in fair value	—			1,292			—			1,963
Other comprehensive loss - settlement	—			(900		)	—			(1,768		)

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	September 30, 2006			December 31, 2005
Fair value of derivative instruments – current asset	$	4,329		$	—
Fair value of derivative instruments – current liability	(1,677		)	—

MarkWest Energy Partners

The Partnership’s primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude.  Swaps and futures contracts may allow the Partnership to reduce volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership’s sales of physical product.  While we largely expect our realized derivative gains and losses to be offset by increases or decreases in the value of our physical sales, we will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative positions that will have no offset.  The volatility in any given period related to unrealized gains or losses can be significant to the overall results of the Partnership, however, we ultimately expect those gains and losses to be offset when they become realized.

The following tables summarize the current derivative positions specific to MarkWest Energy Partner’s segment at September 30, 2006:

Swaps	Contract  Period	Fixed Price (1)		Fair Value
				(in thousands)
Propane - 39,662 Gal/d	Oct 2006	$	1.09	$	150
Propane - 5,000 Gal/d	Oct-Dec 2006	1.08		52
Normal Butane - 9,413 Gal/d	Oct 2006	1.20		34
Natural Gasoline - 16,990 Gal/d	Oct 2006	1.56		150
IsoButane - 7,981 Gal/d	Oct 2006	1.25		31
Ethane - 87,666 Gal/d	Oct 2006	0.61		149
Ethane - 50,000 Gal/d	Jan-Mar 2007	0.78		670
Crude Oil - 435 Bbl/d	Oct-Dec 2006	61.57		(112		)
Crude Oil - 250 Bbl/d	Jan-Sep 2007	65.30		(164		)
Crude Oil - 140 Bbl/d	Jan-Sep 2007	74.10		233
Natural Gas - 13,888 MMBtu/d	Oct 2006	6.33		(1,207		)
				$	(14	)

Basis Swaps	Contract  Period	Fair Value
		(in thousands)
Natural Gas	Oct 2006	$	(2	)
Natural Gas	Nov 2006-Sep 2007	1
		$	(1	)

Options	Contract  Period	Floor		Fair Value
				(in thousands)
Ethane - 50,000 Gal/d	Apr-Jun 2007	$	0.65	$	384
Ethane - 50,000 Gal/d	Jul-Sep 2007	0.65		419
				$	803

17

Collars (Forward Sales)	Contract  Period	Floor (1)		Cap (1)		Fair Value
						(in thousands)
Propane - 20,000 Gal/d	Oct-Dec 2006	$	0.90	$	0.99	$	(20	)
Propane - 10,000 Gal/d	Oct-Dec 2006	0.97		1.15		34
Propane - 23,000 Gal/d	Jan-Mar 2007	1.05		1.28		228
Propane - 30,000 Gal/d	Apr-Jun 2007	0.96		1.16		228
Propane - 30,000 Gal/d	Jul-Sep 2007	0.97		1.16		251
Ethane - 22,950 Gal/d	Oct-Dec 2006	0.65		0.80		86
Crude Oil - 955 Bbl/d	Oct-Dec 2006	57.00		66.59		(95		)
Crude Oil - 78 Bbl/d	Oct-Dec 2006	67.50		77.30		30
Crude Oil - 1,105 Bbl/d	Jan-Sep 2007	69.08		82.43		1,327
Natural Gas - 1,575 MMBtu/d	Oct 2006	8.50		10.05		242
Natural Gas - 1,575 MMBtu/d	Nov 2006-Mar 2007	9.00		12.50		656
Natural Gas - 1,500 MMBtu/d	Jan-Mar 2007	7.25		10.25		(124		)
Natural Gas - 1,900 MMBtu/d	Jan-Sep 2007	7.46		10.20		592
						$	3,435
Current-Total MarkWest Energy Partners						$	4,223

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

The following tables summarize the non-current derivative positions specific to MarkWest Energy Partner’s segment at September 30, 2006:

Swaps	Contract  Period	Fixed Price		Fair Value
				(in thousands)
Crude Oil - 250 Bbl/d	Oct-Dec 2007	$	65.30	$	(82	)
Crude Oil - 140 Bbl/d	Oct-Dec 2007	74.10		61
				$	(21	)

Basis Swaps	Contract  Period	Fair Value
		(in thousands)
Natural Gas	Oct 2007	$	(3	)

Options	Contract Period	Floor		Fair Value
				(in thousands)
Ethane - 50,000 Gal/d	Oct-Dec 2007	$	0.65	$	431

Collars (Forward Sales)	Contract Period	Floor (1)	Cap (1)		Fair Value
					(in thousands)
Crude Oil - 1,105 Bbl/d	Oct-Dec 2007	69.08	$	82.43	$	398
Crude Oil - 1,476 Bbl/d	Jan-Mar 2008	69.76	79.01		492
Crude Oil - 275 Bbl/d	Jan-Dec 2008	64.95	73.10		(5		)
Crude Oil - 275 Bbl/d	Jan-Dec 2008	64.00	74.85		15
Crude Oil - 1,473 Bbl/d	Apr-Jun 2008	69.48	78.66		469
Crude Oil - 1,437 Bbl/d	Jul-Sep 2008	68.90	78.32		427
Crude Oil - 1,473 Bbl/d	Oct-Dec 2008	68.41	77.85		411
Crude Oil - 1,550 Bbl/d	Jan-Dec 2009	63.04	70.91		(432		)
Natural Gas - 1,900 MMBtu/d	Oct-Dec 2007	7.46	10.20		139
Natural Gas - 1,500 MMBtu/d	Jan-Mar 2008	8.00	11.29		118
Propane - 30,000 Gal/d	Oct-Dec 2007	0.98	1.18		275
					$	2,307
Non-current-Total MarkWest Energy Partners					$	2,714

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(1) - A weighted average is used for certain positions.

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

	Three months ended September 30,						Nine months ended September 30,
	2006			2005			2006			2005
Realized losses - revenue	$	(1,719	)	$	(273	)	$	(1,656	)	$	(482	)
Unrealized gains - revenue	14,389			6			7,665			68
Other comprehensive income - changes in fair value	—			111			—			358
Other comprehensive loss - settlement	—			(302		)	—			(482		)

	September 30,  2006			December 31,  2005
Fair value of derivative instruments – current asset	$	5,947		$	—
Fair value of derivative instruments  – non-current asset	3,236			—
Fair value of derivative instruments  – current liability	(1,724		)	(728		)
Fair value of derivative instruments  – non-current liability	(522		)	—

8. 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 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 $5.4 million and $5.9 million for the three and nine months ended September 30, 2006, respectively, resulting in an effective tax rate of 35.4%. Income tax benefit totaled $2.9 million for each of the comparable periods in 2005, resulting in an effective tax rate of 33.5%. Based on our financial projections for the remainder of the year, we expect to be in the 35% federal income tax bracket, and have adjusted our rate accordingly.  The 2006 estimated annual effective income tax rate varies from the statutory rate due to a change in the valuation allowance on state net operating losses (“NOL”), mostly related to state NOL utilization.

The Texas legislature recently passed House Bill 3, 79th Leg., 3d C.S. (2006) (“H.B.3”), signed into law on May 18, 2006. H.B. 3 replaces the state franchise tax system with a margin tax system that expands the type of entities subject to tax to generally include all active business entities. The new margin tax will apply to common entity types that are not currently subject to tax including general and limited partnerships. The margin tax is effective for all reports due on or after January 1, 2008.  The 2008 report would be computed on the new margin tax base reflecting 2007 activity.

Based on this new law, the Partnership recorded a deferred tax liability of $679,000, related to temporary differences that are expected to reverse in future periods.  MarkWest Hydrocarbon recorded a corresponding deferred tax asset of $47,500 for its proportionate share, as it will receive a current tax benefit when the taxes are actually paid.

9. Stock and Incentive Compensation Plans

All previously awarded stock, options and all other compensation arrangements based on the market value of our common stock have been adjusted to reflect the stock dividend of one share of common stock for each ten shares of common stock held paid in May 2006.

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

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	Three months ended September 30,						Nine months ended September 30,
	2006			2005			2006			2005
	(in thousands)
Stock options	$	10		$	306		$	45		$	1,285
Restricted stock	111			21			315			55
General partner interests	8,168			791			12,141			3,507
Subordinated units	21			42			(8		)	103
Restricted units	536			235			1,103			900
Total compensation cost	8,846			1,395			13,596			5,850
Income tax	(3,406		)	(523		)	(5,234		)	(2,194		)
Net compensation cost	$	5,440		$	872		$	8,362		$	3,656

The following summarizes the total compensation cost as of September 30, 2006, related to nonvested awards not yet recognized. The actual compensation cost recognized might differ for the restricted units, as they qualify as liability awards, which are affected by changes in the fair value.

	Amount		Weighted- average  Remaining  Vesting  Period (years)
	(in thousands)
Stock options	$	45	1.2
Restricted stock	425		2.2
Restricted units	1,150		1.9
Total	$	1,620

At September 30, 2006, the Company has five 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.  On June 15, 2006, shareholders approved the 2006 Stock Incentive Plan to replace the 1996 Stock Incentive Plan.  It authorizes the Company to grant 1,000,000 shares and became effective on July 1, 2006.  At September 30, 2006, there were approximately 214,000 options available for grant. The Company may grant options to its non-employee directors for up to 30,000 shares of common stock.

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 third quarter of 2006).

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

	Three months ended September 30,		Nine months ended September 30,
	2006	2005	2006	2005
	(in thousands of shares)
Options exercised, cashless	—	6	7	29
Shares issued, cashless	—	4	3	19
Options exercised, cash	2	4	32	14
Shares issued, cash	2	4	32	14

A summary of the status of the Company’s stock option plans as of September 30, 2006 and 2005, are presented below.

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	Number of  Shares		Weighted- average  Exercise Price		Weighted- average  Remaining  Contractual  Term	Aggregate  Intrinsic Value
Outstanding at December 31, 2005	125,409		$	7.52	7	$	1,565,891
Changes during the period:
Granted	—		—		—	—
Exercised	(40,108	)	6.96		6	605,377
Forfeited	(2,118	)	9.17		6	24,329
Expired	(1,607	)	7.52		8	27,390
Outstanding at September 30, 2006	81,576		$	7.76	4	$	1,651,214
Exercisable at September 30, 2006	50,796
Exercisable at September 30, 2005	82,257

	Three months ended September 30,				Nine months ended September 30,
	2006		2005		2006		2005
Total fair value of options vested during the period	$	7,200	$	173,719	$	120,932	$	298,026
Total intrinsic value of options exercised during the period	46,006		166,338		605,377		594,106

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 third quarter of 2006). On June 15, 2006, shareholders approved the 2006 Stock Incentive Plan to replace the 1996 Stock Incentive Plan.  It authorizes the Company to grant 1,000,000 shares and became effective on July 1, 2006.

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

	Number of  Shares		Weighted- average Grant- date Fair Value
Unvested at January 1, 2006	24,937		$	19.31
Granted	17,209		21.82
Vested	(2,556	)	17.42
Forfeited	(563	)	19.23
Unvested at September 30, 2006	39,027		$	20.54

	Nine months ended September 30,
	2006		2005
Weighted-average grant-date fair value of restricted stock granted during the period	$	375,500	$	133,559
Total fair value of restricted stock vested during the period / total intrinsic value of restricted stock settled during the period	$	44,526	$	—

During the third quarter of 2006 and 2005, the Company did not grant any shares of restricted stock, nor were there any vestings of restricted shares. The Company received no proceeds for issuing restricted stock, and there were no cash settlements during the same periods.

Participation Plan

The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan.  Under it, the Company sells subordinated partnership units of the Partnership or interests in the Partnership’s general partner under a purchase and sale agreement.  There is no maximum contractual term under the

21

Participation Plan. The Company’s capacity to grant further general partner interests is limited by its ownership in the general partner.

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 employees or directors in 2006 or 2005.  MarkWest Hydrocarbon did not reacquire any subordinated units in 2006 or 2005.

The interest in the Partnership’s general partner is sold with certain put-and-call provisions.  These 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, decrease the distributions to all the then existing members; (3) any amendment, alteration or repeal of the provisions of the general partner agreement 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 (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 employment or directorship, MarkWest Hydrocarbon has 12 months following the termination date 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 reasons other than cause, and the remaining 34% became 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 September 30, 2006 and 2005, the Company did not receive or distribute any monies for the issuance or repurchase of 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 restricted units and unit options. It 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 of the Partnership 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 may be accelerated if specific annualized distribution goals are met. During the vesting period, these restricted units are entitled to receive distribution equivalents, which represent cash equal to the amount of distributions made on common units.

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

	Number of units		Weighted-average  grant-date fair  value
Unvested at January 1, 2006	38,864		$	45.60
Granted	30,293		46.64
Vested	(13,493	)	43.86
Forfeited	(1,598	)	45.11
Unvested at September 30, 2006	54,066		$	46.64

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	Three months ended September 30,				Nine months ended September 30,
	2006		2005		2006		2005
Weighted-average grant-date fair value of restricted units granted during the period	$	—	$	50,670	$	1,412,933	$	759,269
Total fair value of restricted units vested during the period / total intrinsic value of restricted units during the period	162,140		11,991		612,513		196,266

During the quarters ended September 30, 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 third quarter of 2006 and 2005, the Partnership did not redeem any restricted units for cash. It issued 12,993 common units in 2006. In 2005 the Partnership issued 8,850 common units and acquired 250 more common units in the open market.

Unit Options. The Compensation Committee has the authority to make grants of unit options under the plan to employees and directors containing such terms as the committee shall determine. Unit options are exercisable over a period determined by the Compensation Committee. Unit options also are exercisable upon a change in control of the Partnership, the general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.

As of September 30, 2006, the Partnership had not granted common unit options.

10. Dividends Paid to Shareholders

Stock Dividend

On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend rate was May 9, 2006. 1,084,647 shares were issued at a fair value of $24.4 million, based upon the last sale price on the record date ($22.50 per share). Cash of $3,200 was paid in lieu of fractional shares, based upon the last sale price on the record date.

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, payable on June 5, 2006, to the stockholders of record as of the close of business on May 26, 2006. The ex-dividend date was May 24, 2006.

On July 27, 2006, the Company’s Board of Directors declared a quarterly cash dividend of $0.24 per share, payable on August 21, 2006, to the stockholders of record as of the close of business on August 14, 2006. The ex-dividend date was August 10, 2006.

On October 26, 2006, the Company’s Board of Directors declared a quarterly cash dividend of $0.28 per share, payable on November 21, 2006, to the stockholders of record as of the close of business on November 9, 2006. The ex-dividend date will be November 7, 2006.

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11. Commitments and Contingencies

Legal

In the ordinary course of business, the Company is subject to a variety of risks and disputes normally 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, 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, and the cases were consolidated into Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137.

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 explosion and 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 underway following the remand back to state court. The trial is scheduled to begin February 5, 2007.

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.

In late June 2006 a Notice of Probable Violation and Proposed Civil Penalty (NOPV) was issued by OPS to both MarkWest Hydrocarbon and the unaffiliated owner of the pipeline, with a proposed penalty in the aggregate amount of $1,070,000. OPS has placed the matter in abeyance until further notice pending further discussions and exploration of appropriate settlement and resolution of the NOPV.

Related to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership have 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 related to the pipeline incident. These include the Company’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred for transporting the liquids while the pipeline was out of service; the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). 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 it is 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 the 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. Discovery in the action is continuing.

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

24

beyond the contract’s lump sum price performed by the contractor. On October 12th, 2006, the Sixth Circuit affirmed the District Court’s previous grant of Summary Judgment against Ross Bros. Construction.

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.

Office Lease Obligation

The Partnership entered into a ten-year office lease and relocated its and MarkWest Hydrocarbon, Inc.’s corporate headquarters to the Park Central Building, in downtown Denver, Colorado in July 2006. 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 (in thousands):

Year ending December 31,
2006	$	—
2007	927
2008	972
2009	1,017
2010	1,045
2011 and thereafter	5,984
Total	$	9,945

The Partnership’s former principal executive office was located in a building leased by MarkWest Hydrocarbon.  A portion of the lease cost for that building historically had been allocated to the Partnership. In accordance with SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, the Company incurred a liability associated with the cancelled lease of $1.3 million, of which $0.8 million was allocated to the Partnership.

12. Segment Reporting

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

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

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

The Company evaluates the performance of its segments and allocates resources to them based on operating income.  There were no intersegment revenues prior to May 24, 2002.  The Company conducts its operations in the United States.

The table below presents information about net income/(loss) for the reported segments for the three and nine months ended September 30, 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.

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	MarkWest  Hydrocarbon Standalone			MarkWest  Energy  Partners			Consolidating Entries			Total
Three months ended September 30, 2006: (in thousands)
Revenues:
Revenue	$	53,223		$	149,987		$	(19,694	)	$	183,516
Derivative gain	10,051			12,670			—			22,721
Total revenue	63,274			162,657			(19,694		)	206,237
Purchased product costs	40,150			81,816			(13,746		)	108,220
Facility expenses	5,099			15,505			(5,948		)	14,656
Selling, general and administrative expenses	5,991			13,078			—			19,069
Depreciation	221			7,905			—			8,126
Amortization of intangible assets	—			4,029			—			4,029
Accretion of asset retirement and lease obligations	—			24			—			24
Income from operations	11,813			40,300			—			52,113
Other income (expense):
Earnings from unconsolidated affiliates	—			1,067			—			1,067
Interest income	34			230			—			264
Interest expense	(60		)	(9,523		)	—			(9,583		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(55		)	(6,066		)	—			(6,121		)
Dividend income	112			—			—			112
Miscellaneous income	8			3,970			—			3,978
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	11,852			29,978			—			41,830
Income tax expense	(5,388		)	—			—			(5,388		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(26,438		)	(26,438		)
Interest in net income of consolidated subsidiary	3,540			—			(3,540		)	—
Net income (loss)	$	10,004		$	29,978		$	(29,978	)	$	10,004

	Markwest  Hydrocarbon Standalone			Markwest  Energy  Partners			Consolidating Entries			Total
Three months ended September 30, 2005: (in thousands)
Revenues:
Revenue	$	56,859		$	130,835		$	(16,021	)	$	171,673
Derivative loss	(781		)	(267		)	—			(1,048		)
Total revenue	56,078			130,568			(16,021		)	170,625
Purchased product costs	57,789			98,874			(10,787		)	145,876
Facility expenses	4,802			12,514			(5,234		)	12,082
Selling, general and administrative expenses	2,591			5,322			—			7,913
Depreciation	254			4,771			—			5,025
Amortization of intangible assets	—			2,098			—			2,098
Accretion of asset retirement and lease obligations	(1		)	117			—			116
Income (loss) from operations	(9,357		)	6,872			—			(2,485		)
Other income (expense):
Losses from unconsolidated affiliates	—			(999		)	—			(999		)
Interest income	191			80			—			271
Interest expense	(30		)	(4,950		)	—			(4,980		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(61		)	(496		)	—			(557		)
Dividend income	101			—			—			101
Miscellaneous income	47			18			—			65
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	(9,109		)	525			—			(8,584		)
Income tax benefit	2,868			—			—			2,868
Non-controlling interest in net income of consolidated subsidiary	—			77			(49		)	28
Interest in net income of consolidated subsidiary	553			—			(553		)	—
Net income (loss)	$	(5,688	)	$	602		$	(602	)	$	(5,688	)

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	MarkWest  Hydrocarbon Standalone			MarkWest  Energy  Partners			Consolidating Entries			Total
Nine months ended September 30, 2006: (in thousands)
Revenues:
Revenue	$	217,503		$	448,770		$	(55,288	)	$	610,985
Derivative gain	2,397			6,009			—			8,406
Total revenue	219,900			454,779			(55,288		)	619,391
Purchased product costs	184,781			258,791			(37,327		)	406,245
Facility expenses	15,574			44,964			(17,961		)	42,577
Selling, general and administrative expenses	13,102			30,404			—			43,506
Depreciation	820			22,462			—			23,282
Amortization of intangible assets	—			12,072			—			12,072
Accretion of asset retirement and lease obligations	—			75			—			75
Income from operations	5,623			86,011			—			91,634
Other income (expense):
Earnings from unconsolidated affiliates	—			3,240			—			3,240
Interest income	397			709			—			1,106
Interest expense	(212		)	(31,213		)	—			(31,425		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(105		)	(7,700		)	—			(7,805		)
Dividend income	327			—			—			327
Miscellaneous income	160			7,577			—			7,737
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	6,190			58,624			—			64,814
Income tax benefit (expense)	(5,719		)	(679		)	543			(5,855		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(48,255		)	(48,255		)
Interest in net income of consolidated subsidiary	10,233			—			(10,233		)	—
Net income (loss)	$	10,704		$	57,945		$	(57,945	)	$	10,704

	Markwest  Hydrocarbon Standalone			Markwest  Energy  Partners			Consolidating Entries			Total
Nine months ended September 30, 2005: (in thousands)
Revenues:
Revenue	$	174,733		$	323,579		$	(46,533	)	$	451,779
Derivative loss	(1,347		)	(414		)	—			(1,761		)
Total revenue	173,386			323,165			(46,533		)	450,018
Purchased product costs	159,340			233,521			(29,932		)	362,929
Facility expenses	15,723			33,205			(16,601		)	32,327
Selling, general and administrative expenses	8,653			16,487			—			25,140
Depreciation	1,088			13,673			—			14,761
Amortization of intangible assets	—			6,288			—			6,288
Accretion of asset retirement and lease obligations	1			136			—			137
Income (loss) from operations	(11,419		)	19,855			—			8,436
Other income (expense):
Losses from unconsolidated affiliates	—			(9		)	—			(9		)
Interest income	631			210			—			841
Interest expense	(91		)	(13,182		)	—			(13,273		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(183		)	(1,468		)	—			(1,651		)
Dividend income	289			—			—			289
Miscellaneous income	244			56			—			300
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	(10,529		)	5,462			—			(5,067		)
Income tax benefit	2,900			—			—			2,900
Non-controlling interest in net income of consolidated subsidiary	—			76			(3,667		)	(3,591		)
Interest in net income of consolidated subsidiary	1,871			—			(1,871		)	—
Net income (loss)	$	(5,758	)	$	5,538		$	(5,538	)	$	(5,758	)

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13. Subsequent Events

Debt Offering

On October 18, 2006, the Partnership and its subsidiary, MarkWest Energy Finance Corporation, completed their private placement of $75.0 million in aggregate principal amount of 81¤2% senior notes due 2016 to qualified institutional buyers. The Notes were offered as additional debt securities under an indenture pursuant to which the Partnership had previously issued $200.0 million in aggregate principal amount of our 8 1/2% Senior Notes due 2016. The 2016 Senior Notes will mature on July 15, 2016, and interest is payable on each July 15 and January 15, commencing January 15, 2007. The net proceeds from the private placement were approximately $74.5 million, after deducting the initial purchasers’ discounts and legal, accounting and other transaction expenses. The Partnership used a portion of the net proceeds from the offering to retire the term debt under the Partnership Credit Facility and will use the remaining net proceeds to fund capital expenditures and for general corporate purposes. The initial purchaser, RBC Capital Markets Corporation, is a lender under the Partnership Credit Facility.

Repurchase of General Partner Interest

On October 13, 2006, MarkWest Hydrocarbon, Inc. completed the purchase from the Company’s retired Chief Financial Officer of a 0.5% Class B Membership Interest in the Company’s subsidiary, MarkWest Energy GP, LLC (the “General Partner”).  The General Partner is the general partner of MarkWest Energy Partners, L.P.

Newfield Capital Expenditures

On September 21, 2006, the Partnership announced a strategic agreement with Newfield Exploration that involves the construction and operation of a new gathering and compression system to support all Newfield-operated wells within a 200 square mile project area situated in a four-county region in the Arkoma Basin in eastern Oklahoma. While the Partnership has not made any significant capital expenditures as of September 30, 2006, it does expect its total capital investment from 2006 through 2011 to range from $275 million to $325 million with between $140 million and $175 million occurring by the end of 2007.

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

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

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

Forward-looking statements relate to, among other things:

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

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

·Our expectations regarding natural gas, 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 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 risk that third-party natural gas exploration and production activities will not occur or be successful.

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

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

·Our substantial debt and other financial obligations could adversely affect our financial condition.

·The Partnership’s ability to successfully integrate its recent and future acquisitions.

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

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

·Changes in general economic conditions in regions where our products are located.

·The threat of terrorist attacks or war.

·Winter weather conditions.

Other unknown or unpredictable factors could also affect future results. The Company does not publicly update 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.

Overview

MarkWest Hydrocarbon reported net income of $10.0 million, or $0.83 per diluted share, for the three months ended September 30, 2006, compared to a net loss of $5.7 million, or $0.48 per diluted share, for the corresponding quarter of 2005. The Company also reported net income of $10.7 million, or $0.89 per diluted share for the nine months ended September 30, 2006, compared to a net loss of $5.8 million, or $0.49 per diluted share, for the corresponding period 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.

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MarkWest Hydrocarbon Standalone Results

For the three months ended September 30, 2006, MarkWest Hydrocarbon Standalone reported operating income of $11.8 million, compared to an operating loss of $9.4 million for the comparable quarter of 2005.  MarkWest Hydrocarbon Standalone also reported net income of $10.0 million for the three months ended September 30, 2006, compared to a net loss of $5.7 million for the comparable quarter of 2005.

For the nine months ended September 30, 2006, MarkWest Hydrocarbon Standalone reported operating income of $5.6 million, compared to an operating loss of $11.4 million for the comparable period of 2005. MarkWest Hydrocarbon Standalone also reported net income of $10.7 million for the nine months ended September 30, 2006, compared to a net loss of $5.8 million for the comparable period of 2005.

Stock Dividend

On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006. 1,084,647 shares were issued at a fair value of $24.4 million, based upon the last sale price on the record date ($22.50 per share). Cash of $3,200 was paid in lieu of fractional shares, based upon the last sale price on the record date.

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, payable on June 5, 2006, to the stockholders of record as of the close of business on May 26, 2006. The ex-dividend date was May 24, 2006.

On July 27, 2006, the Company’s Board of Directors declared a quarterly cash dividend of $0.24 per share, payable on August 21, 2006, to the stockholders of record as of the close of business on August 14, 2006. The ex-dividend date was August 10, 2006.

On October 26, 2006, the Company’s Board of Directors declared a quarterly cash dividend of $0.28 per share, payable on November 21, 2006, to the stockholders of record as of the close of business on November 9, 2006. The ex-dividend date will be November 7, 2006.

MarkWest Energy Partners Results

For the three months ended September 30, 2006, the Partnership reported operating income of $40.3 million compared to $6.9 million for the corresponding quarter of 2005, an increase of $33.4 million, or 484%. The Partnership also reported net income of $30.0 million in the third quarter of 2006, compared to $0.6 million in 2005.

For the nine months ended September 30, 2006, the Partnership reported operating income of $86.0 million compared to $19.9 million for the corresponding period of 2005, an increase of $66.1 million, or 332%. The Partnership also reported net income of $57.9 million for the nine months ended September 30, 2006, compared to $5.5 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) in support of our Appalachian processing agreements and increasing shareholder value by growing MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or “The Partnership”), our consolidated subsidiary and a publicly traded master limited partnership. 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

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processing agreements in Appalachia.  As of September 30, 2006, the Company owned a 17% interest in the Partnership, consisting of the following:

·1,200,000 subordinated units and 1,269,496 common units, representing a 15% 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 equity income derived from MarkWest Energy Partners, we generate the majority of our revenues and net operating margin (defined and discussed 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. Our agreements with this customer run through December 31, 2015, with annual renewals thereafter.

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.

During 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. Since February 2004, the Company has been engaged in the wholesale propane marketing business through a third party agency agreement. In June of 2006, that agreement was terminated. 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.

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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 different types of arrangements:

·Fee-based arrangements. The Partnership receives a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, these arrangements provide for minimum annual payments. If a sustained decline in commodity prices were to result in a decline in volumes, the Partnership’s revenues from these arrangements would be reduced.

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

·Percent-of-index arrangements.  The Partnership generally purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount, or (3) a percentage discount to a specified index price less an additional fixed amount. It then gathers and delivers the natural gas to pipelines, where it resells the natural gas at the index price, or at a different percentage discount to the index price. The net operating margins the Partnership realizes under these arrangements decrease in periods of low natural gas prices, because these net operating margins are based on a percentage of the index price. Conversely, their net operating margins increase during periods of high natural gas prices.

·Keep-whole arrangements.  The Partnership gathers natural gas from the producer, processes the natural gas, and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers, or make cash payment to the producers equal to the energy content of this natural gas. Accordingly, under these arrangements the Partnership’s revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decreases as the price of natural gas increases relative to the price of condensate and NGLs.

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

The terms of the Partnership’s contracts vary based on gas quality, 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 September 30, 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

32

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 and nine months ended September 30, 2006, approximately 8.3% and 7.9% of East Texas inlet volumes were processed pursuant to keep-whole contracts.

For the nine months ended September 30, 2006, MarkWest Energy Partners calculated the following approximate 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	13	%	24	%	46	%	17	%	100	%
Net operating margin	30	%	40	%	13	%	17	%	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.

On September 21, 2006, the Partnership announced a strategic agreement with Newfield Exploration that involves the construction and operation of a new gathering and compression system to support all Newfield-operated wells within a 200 square mile project area situated in a four-county region in the Arkoma Basin in eastern Oklahoma. The agreement requires MarkWest Energy Partners to construct all required gathering pipelines, compression, dehydration and treating equipment to gather Newfield’s gas at the individual well locations within the project area.  The Partnership projects the capital investment from 2006 through 2011 to range from $275 million to $325 million with between $140 million and $175 million occurring by the end of 2007.  

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 nine months ended September 30, 2006, we accounted for 12% of the Partnership’s revenues and 12% of its net operating margin.  This represents a decrease from the nine months ended September 30, 2005, when we accounted for 16% of the Partnership’s revenues and 22% 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 $795 million, net of working capital. The following table contains information regarding each of these acquisitions:

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Name	Assets	Location	Consideration		Closing Date
			(in millions)
Javelina (1)	Gas processing and fractionation facility	Corpus Christi, TX	$	398.8	November 1, 2005
Starfish (2)	Natural gas pipeline, gathering system and dehydration facility	Gulf of Mexico/Southern Louisiana	$	41.7	March 31, 2005
East Texas	Gathering system and gas 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 September 30,				Nine Months Ended September 30,
	2006	2005	% Change		2006	2005	% Change
MarkWest Hydrocarbon Standalone:
Marketing
Hydrocarbon frac spread sales (gallons)	22,103,000	22,871,000	(3.4	)%	80,615,000	85,433,000	(5.6	)%
Maytown sales (gallons)	11,275,000	10,132,000	11.3	%	32,226,000	31,051,000	3.8	%
Total NGL product sales (gallons)(1)	33,378,000	33,003,000	1.1	%	112,841,000	116,484,000	(3.1	)%
Wholesale
NGL product sales (gallons)(2)	4,052,000	14,815,000	(72.6	)%	39,115,000	41,574,000	(5.9	)%
MarkWest Energy Partners:
East Texas(3)
Gathering systems throughput (Mcf/d)	393,000	330,000	19.1	%	371,000	313,000	18.5	%
NGL product sales (gallons)	42,015,000	38,362,000	9.5	%	117,912,000	88,958,000	32.5	%
Oklahoma
Foss Lake gathering systems throughput (Mcf/d)	86,000	81,000	6.2	%	86,000	73,000	17.8	%
Arapaho NGL product sales (gallons)	19,553,000	14,506,000	34.8	%	57,586,000	46,180,000	24.7	%
Other Southwest(4)
Appleby gathering systems throughput (Mcf/d)	34,000	38,000	(10.5	)%	34,000	33,000	3.0	%
Other gathering systems throughput (Mcf/d)	18,000	16,000	12.5	%	20,000	16,000	25.0	%
Lateral throughput volumes (Mcf/d)	111,000	126,000	(11.9	)%	84,000	90,000	(6.7	)%
Appalachia(5)
Natural gas processed for a fee (Mcf/d)	198,000	188,000	5.3	%	200,000	197,000	1.5	%
NGLs fractionated for a fee (Gal/day)	453,000	396,000	14.4	%	451,000	426,000	5.9	%
NGL product sales (gallons)	11,275,000	10,132,000	11.3	%	32,226,000	31,051,000	3.8	%
Michigan
Natural gas processed for a fee (Mcf/d)	7,300	6,500	12.3	%	6,500	6,700	(3.0	)%
NGL product sales (gallons)	1,501,000	1,391,000	7.9	%	4,344,000	4,447,000	(2.3	)%
Crude oil transported for a fee (Bbl/d)	14,600	14,100	3.5	%	14,600	14,100	3.5	%
Gulf Coast(6)
Natural gas processed for a fee (Mcf/d)	125,000	NA	NA		125,000	NA	NA
NGLs fractionated for a fee (Gal/day)	1,097,000	NA	NA		1,090,000	NA	NA

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(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 own that produce revenue on a per-unit-of-throughput basis. MarkWest Energy Partners receive a flat fee from its 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.

Three months ended September 30, 2006, compared to the three months ended September 30, 2005

The following reconciles this non-GAAP financial measure to the most comparable GAAP financial measure for the three and nine months ended September 30, 2006 and 2005:

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Three months ended September 30, 2006: (in thousands)
Revenues:
Revenue	$	53,223		$	149,987		$	(19,694	)	$	183,516
Derivative gain	10,051			12,670			—			22,721
Total revenue	63,274			162,657			(19,694		)	206,237
Purchased product costs	40,150			81,816			(13,746		)	108,220
Net operating margin	23,124			80,841			(5,948		)	98,017
Operating expenses:
Facility expenses	5,099			15,505			(5,948		)	14,656
Selling, general and administrative expenses	5,991			13,078			—			19,069
Depreciation	221			7,905			—			8,126
Amortization of intangible assets	—			4,029			—			4,029
Accretion of asset retirement and lease obligations	—			24			—			24
Income from operations	11,813			40,300			—			52,113
Other income (expense):
Earnings from unconsolidated affiliates	—			1,067			—			1,067
Interest income	34			230			—			264
Interest expense	(60		)	(9,523		)	—			(9,583		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(55		)	(6,066		)	—			(6,121		)
Dividend income	112			—			—			112
Miscellaneous income	8			3,970			—			3,978
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	11,852			29,978			—			41,830
Income tax expense	(5,388		)	—			—			(5,388		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(26,438		)	(26,438		)
Interest in net income of consolidated subsidiary	3,540			—			(3,540		)	—
Net income (loss)	$	10,004		$	29,978		$	(29,978	)	$	10,004

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	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Three months ended September 30, 2005: (in thousands)
Revenues:
Revenue	$	56,859		$	130,835		$	(16,021	)	$	171,673
Derivative loss	(781		)	(267		)	—			(1,048		)
Total revenue	56,078			130,568			(16,021		)	170,625
Purchased product costs	57,789			98,874			(10,787		)	145,876
Net operating margin	(1,711		)	31,694			(5,234		)	24,749
Operating expenses:
Facility expenses	4,802			12,514			(5,234		)	12,082
Selling, general and administrative expenses	2,591			5,322			—			7,913
Depreciation	254			4,771			—			5,025
Amortization of intangible assets	—			2,098			—			2,098
Accretion of asset retirement and lease obligations	(1		)	117			—			116
Income (loss) from operations	(9,357		)	6,872			—			(2,485		)
Other income (expense):
Losses from unconsolidated affiliates	—			(999		)	—			(999		)
Interest income	191			80			—			271
Interest expense	(30		)	(4,950		)	—			(4,980		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(61		)	(496		)	—			(557		)
Dividend income	101			—			—			101
Miscellaneous income	47			18			—			65
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	(9,109		)	525			—			(8,584		)
Income tax benefit	2,868			—			—			2,868
Non-controlling interest in net income of consolidated subsidiary	—			77			(49		)	28
Interest in net income of consolidated subsidiary	553			—			(553		)	—
Net income (loss)	$	(5,688	)	$	602		$	(602	)	$	(5,688	)

MarkWest Hydrocarbon Standalone

Revenue. Revenue decreased $3.6 million, or 6%, for the three months ended September 30, 2006, compared to the corresponding period of 2005. We realized a $9.7 million decrease in our gas marketing business due primarily to lower prices and volumes of $0.07 per MMBtu and 14,500 MMBtu per day, respectively.  The $10.1 million decrease in revenues in our wholesale business can primarily be attributed to the expiration of a marketing arrangement that resulted in lower volumes of 114,700 Gal/d.  This decrease was partially offset by a price increase of $0.085 per gallon.  The above decreases were partially offset by an improvement in our frac spread NGL revenues of $7.2 million, an increase primarily the result of increases in prices and volumes.  Additionally, the revaluation of our long-term shrink obligation increased revenue by

36

$1.7 million in the three months ended September 30, 2006, compared to a $7.5 million decrease in 2005, resulting in a $9.2 million positive swing for the period-over-period comparison. 

Derivative gain (loss). Gains from derivative instruments increased $10.8 million during the three months ended September 30, 2006, compared to the corresponding period in 2005.  This increase was primarily due to the mark-to-market adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments.  The mark-to-market adjustments resulted in a $10.3 million increase in unrealized gains, which are non-cash items, and a $0.5 million decrease in realized losses, when comparing 2006 to 2005 results.

Purchased Product Costs. Purchased product costs decreased $17.6 million, or 31%, for the three months ended September 30, 2006, compared to the corresponding period of 2005. The decrease was primarily due to our natural gas marketing business which reflected a decrease of $9.4 million.  This was primarily due to a decrease in volumes of 14,500 MMBtu per day, and was partially offset by an increase in prices of $0.004 per MMBtu.  Additionally, our wholesale business incurred a decrease of $9.8 which was driven by decreased volumes of nearly 114,700 Gal/d, and partially offset by increased prices of $0.10 per gallon.  These decreases were partially offset by an increase in our frac spread purchase costs of $1.6 million resulting from increased prices and volumes.

Facility Expenses. Facility expenses increased by approximately $0.3 million, or 6%, during the three months ended September 30, 2006, compared to corresponding quarter of 2005. The primary reason for the increase was due to higher Siloam storage fees, higher Kenova, Boldman and Cobb plant processing fees, and higher ALPS transportation fees.  These increases were partially offset by reduced inventory losses.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $3.4 million, or 131%, during the three months ended September 30, 2006, compared to the same period in 2005. This increase was primarily due to a $3.1 million non-cash increase to the participation plan compensation expense as a result of the Partnership’s increased market value.

Income taxes. Income tax expense increased by $8.3 million due to higher pre-tax book income for the three months ended September 30, 2006, compared to the same period of 2005.  The 2006 estimated annual effective income tax rate varies from the statutory rate due to a change in the valuation allowance on state net operating losses (“NOL”), mostly related to state NOL utilization.

MarkWest Energy Partners

Revenue. Revenue for the three months ended September 30, 2006, increased by $19.2 million, or 15%, compared to the corresponding quarter of 2005, mostly due to the Partnership’s Javelina acquisition in November 2005, which contributed $19.1 million.  Additionally, the start-up of several new gathering expansions in East Texas resulted in a $6.1 million increase in revenue.  These increases were partially offset by a decrease in Other Southwest of $7.8 million, which is mostly attributable to lower gas prices and a new contract with a customer in the Appleby system.

Derivative gain (loss). Gains from derivative instruments increased $12.9 million during the three months ended September 30, 2006, compared to the corresponding period in 2005.  This increase was primarily due to the mark-to-market adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments.  The mark-to-market adjustments resulted in a $14.4 million increase in unrealized gains, which are non-cash items, and a $1.5 million increase in realized losses, when comparing 2006 to 2005 results.

Purchased Product Costs. Purchased product costs decreased during the three months ended September 30, 2006, by $17.1 million, or 17%, compared to the corresponding quarter of 2005. This decrease was primarily due to a $3.4 million decrease in costs related to the conversion of contracts in East Texas; an $8.1 million decrease in Oklahoma driven by a 22% decrease in purchase prices; and a $7.6 million decrease in Other Southwest driven by lower gas prices and volumes.  These decreases were partially offset by a $1.9 increase in Appalachia due to increases in both prices and volumes.

Facility Expenses. Facility expenses increased approximately $3.0 million, or 24%, during the three months ended September 30, 2006, compared to the corresponding quarter of 2005, primarily due to the Partnership’s November 2005 Javelina Acquisition, which contributed $3.6 million; and $1.2 million related to the new Carthage facility in East Texas, which started operations on January 1, 2006.  These increases were partially offset by a $2.2 million decrease in Appalachia due to costs incurred to repair the ALPS pipeline in 2005.

37

Selling, General and Administrative Expense.  Selling, general and administrative expenses increased $7.8 million, or 146%, during the three months ended September 30, 2006, relative to the comparable period in 2005. The increase is primarily due to higher non-cash, equity-based compensation expense of $5.2 million, attributable to the Partnership’s increased market value; labor costs of $1.2 million, related to additional personnel to support our growth and strategic objectives; and higher insurance premiums of $0.6 million.

Depreciation.  Depreciation expenses increased $3.1 million, or 66%, during the three months ended September 30, 2006, compared to the corresponding quarter of 2005, primarily due to the Partnership’s November 2005 Javelina Acquisition, which contributed $1.6 million; and $0.7 million in East Texas related to the to the new Carthage gas plant and Blocker gathering system.

Equity in Earnings from Unconsolidated Affiliates. Equity in earnings from unconsolidated affiliates is primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC.  During the three months ended September 30, 2006, our equity in earnings from unconsolidated affiliates increased $2.1 million, or 207%, due to the restoration of operations resulting from the completion of the majority of repairs necessary after the 2005 hurricane season.

Interest Expense and Amortization of Deferred Financing Costs (a component of interest expense). Interest and amortization expense increased $10.1 million during the three months ended September 30, 2006, relative to the comparable period in 2005, primarily due to increased debt levels resulting from the financing of our November 2005 Javelina acquisition and higher interest rates. The increase in the amortization relative to the comparable period in 2005 is attributable to deferred financing costs associated with our debt refinancing completed in July 2006. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Miscellaneous Income.  Miscellaneous income increased by $4.0 million during the three months ended September 30, 2006, recoveries to the comparable period in 2005, due almost entirely to the Partnership recognizing $4.1million of income from insurance recoveries, net of Starfish insurance premiums, recovered from damages from Hurricane Rita.

Texas Margin Tax.  Texas passed a margin tax law that subjects the Partnership to an entity-level tax on the portion of its income that is generated in Texas. We recorded a deferred tax liability of $0.7 million in the second quarter of 2006, related to the Partnership’s temporary differences that are expected to reverse in future periods.

Nine months ended September 30, 2006, compared to the nine months ended September 30, 2005

The following includes reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure for the nine months ended September 30, 2006 and 2005:

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Nine months ended September 30, 2006: (in thousands)
Revenues:
Revenue	$	217,503		$	448,770		$	(55,288	)	$	610,985
Derivative gain	2,397			6,009			—			8,406
Total revenue	219,900			454,779			(55,288		)	619,391
Purchased product costs	184,781			258,791			(37,327		)	406,245
Net operating margin	35,119			195,988			(17,961		)	213,146
Operating expenses:
Facility expenses	15,574			44,964			(17,961		)	42,577
Selling, general and administrative expenses	13,102			30,404			—			43,506
Depreciation	820			22,462			—			23,282
Amortization of intangible assets	—			12,072			—			12,072
Accretion of asset retirement and lease obligations	—			75			—			75
Income from operations	5,623			86,011			—			91,634
Other income (expense):
Earnings from unconsolidated affiliates	—			3,240			—			3,240
Interest income	397			709			—			1,106
Interest expense	(212		)	(31,213		)	—			(31,425		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(105		)	(7,700		)	—			(7,805		)
Dividend income	327			—			—			327
Miscellaneous income	160			7,577			—			7,737
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	6,190			58,624			—			64,814
Income tax benefit (expense)	(5,719		)	(679		)	543			(5,855		)
Non-controlling interest in net income of consolidated subsidiary	—			—			(48,255		)	(48,255		)
Interest in net income of consolidated subsidiary	10,233			—			(10,233		)	—
Net income (loss)	$	10,704		$	57,945		$	(57,945	)	$	10,704

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	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Consolidating Entries			Total
Nine months ended September 30, 2005: (in thousands)
Revenues:
Revenue	$	174,733		$	323,579		$	(46,533	)	$	451,779
Derivative loss	(1,347		)	(414		)	—			(1,761		)
Total revenue	173,386			323,165			(46,533		)	450,018
Purchased product costs	159,340			233,521			(29,932		)	362,929
Net operating margin	14,046			89,644			(16,601		)	87,089
Operating expenses:
Facility expenses	15,723			33,205			(16,601		)	32,327
Selling, general and administrative expenses	8,653			16,487			—			25,140
Depreciation	1,088			13,673			—			14,761
Amortization of intangible assets	—			6,288			—			6,288
Accretion of asset retirement and lease obligations	1			136			—			137
Income (loss) from operations	(11,419		)	19,855			—			8,436
Other income (expense):
Losses from unconsolidated affiliates	—			(9		)	—			(9		)
Interest income	631			210			—			841
Interest expense	(91		)	(13,182		)	—			(13,273		)
Amortization of deferred financing costs and original issue discount (a component of interest expense)	(183		)	(1,468		)	—			(1,651		)
Dividend income	289			—			—			289
Miscellaneous income	244			56			—			300
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	(10,529		)	5,462			—			(5,067		)
Income tax benefit	2,900			—			—			2,900
Non-controlling interest in net income of consolidated subsidiary	—			76			(3,667		)	(3,591		)
Interest in net income of consolidated subsidiary	1,871			—			(1,871		)	—
Net income (loss)	$	(5,758	)	$	5,538		$	(5,538	)	$	(5,758	)

MarkWest Hydrocarbon Standalone

Revenue. Revenue increased $42.8 million, or 24%, for the nine months ended September 30, 2006, compared to the corresponding period of 2005. This was due in part to a $2.9 million increase in wholesale NGL revenues, which was driven by a $0.1272 per gallon price increase and partially offset by a volume decrease of nearly 8,000 Gal/d.  Frac spread NGL revenues improved by $18.8 million, due primarily to an increase in prices of $0.21 per gallon, and partially offset by reduced volumes of 14,900 Gal/d.  We also realized a $5.4 million increase in our gas marketing business due to higher prices and volumes of $0.80 per MMBtu and 741 MMBtu per day, respectively.  The revaluation of our long-term shrink obligation also increased revenue by $7.4 million for the nine months ended September 30, 2006, compared to an $8.3 million decrease in 2005, resulting in a $15.7 million positive impact to the period-over-period comparison.

Derivative gain (loss). Gains from derivative instruments increased $3.7 million during the nine months ended September 30, 2006, compared to the corresponding period in 2005.  This increase was primarily due to the mark-to-market

39

adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments.  The mark-to-market adjustments resulted in a $1.9 million increase in unrealized gains, which are non-cash items, and a $1.8 million decrease in realized losses, when comparing 2006 to 2005 results.

Purchased Product Costs. Purchased product costs increased $25.4 million, or 16%, for the nine months ended September 30, 2006, compared to the corresponding period of 2005. The product costs increased $3.1 million for our wholesale business.  This increase was driven by increased prices of $0.14 per gallon and  was partially offset by decreasing volumes of nearly 8,000 Gal/d. Frac spread purchase costs increased by $17.6 million due to price increases of $0.17 per gallon, partially offset by reduced volumes of 14,900 Gal/d.  The natural gas marketing business reported an increase of $4.7 million, due primarily to increases in both prices and volumes of $0.67 per MMBtu and 741 MMBtu per day, respectively.

Facility Expenses. Facility expenses decreased by approximately $0.1 million, or 1%, during the nine months ended September 30, 2006, compared to corresponding quarter of 2005. The primary reason for the decrease was reduced inventory losses, which were partially offset by increased Siloam storage fees, higher Kenova, Boldman and Cobb plant processing fees, and increased ALPS transportation fees.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $4.4 million, or 51%, during the nine months ended September 30, 2006, compared to the same period in 2005. This increase was due primarily to a $2.7 million non-cash increase to the participation plan compensation expense, attributable to the Partnership’s increased market value and a $1.0 million increase to labor and benefits costs necessary to manage the Partnership’s new acquisitions.

Depreciation. Depreciation expense decreased by $0.3 million, or 25%, during the nine months ended September 30, 2006, compared to the corresponding period of 2005 due to certain fixed assets becoming fully depreciated in 2005.

Income taxes. Income tax expense increased by $8.6 million due to higher pre-tax book income for the nine months ended September 30, 2006, compared to the same period of 2005. The 2006 estimated annual effective income tax rate varies from the statutory rate due to a change in the valuation allowance on state net operating losses (“NOL”), mostly related to state NOL utilization.

MarkWest Energy Partners

Revenues. Revenue for the nine months ended September 30, 2006, increased by $125.2 million, or 39%, compared to the corresponding period of 2005.  The increased revenue was primarily due to the Partnership’s Javelina acquisition in November 2005, which contributed $53.0 million.  Additionally, increased volumes and prices resulted in revenue increases in Oklahoma of $27.1 million, East Texas of $36.3 million and Appalachia of $8.8 million.

Derivative gain (loss). Gains from derivative instruments increased $6.4 million during the nine months ended September 30, 2006, compared to the corresponding period in 2005.  This increase was primarily due to the mark-to-market adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments.  The mark-to-market adjustments resulted in a $7.6 million increase in unrealized gains, which are non-cash items, and a $1.2 million increase in realized losses, when comparing 2006 to 2005 results.

Purchased Product Costs. Purchased product costs increased during the nine months ended September 30, 2006, by $25.3 million, or 11%, compared to the corresponding quarter of 2005. This increase was primarily due to $9.8 million in costs related to increased volumes at the new Carthage facility in East Texas and increased expenses driven by higher volumes in Oklahoma and Appalachia of $12.9 and $4.4 million, respectively.  These costs were partially offset by a decrease in purchase product costs of $2.1 million in Other Southwest primarily due to lower gas prices and a new contract with a customer in the Appleby system.

Facility Expenses. Facility expenses increased approximately $11.8 million, or 35%, during the nine months ended September 30, 2006, compared to the corresponding quarter of 2005, primarily due to the Partnership’s November 2005 Javelina acquisition, which contributed $8.7 million.  We also experienced a $4.1million increase in East Texas related to our new Carthage facility, which started operations on January 1, 2006, and a $2.0 million increase in Oklahoma.  These increases were partially offset by a decrease in Appalachia of $4.3 million due to decreased repair expenses related to the ALPS pipeline failure.

Selling, General and Administrative Expense.  Selling, general and administrative expenses increased $13.9 million, or 84%, during the nine months ended September 30, 2006, relative to the comparable period in 2005. The increase is due to higher

40

non-cash, equity-based compensation expense of $6.1 million, primarily due to the Partnership’s increased market value; labor costs related to additional personnel to support our growth and strategic objectives of $3.3 million; higher insurance premiums and taxes of $2.1 million; and the one-time charge associated with terminating the old headquarters lease of $0.9 million.

Depreciation.  Depreciation expenses increased $8.8 million, or 64%, during the nine months ended September 30, 2006, compared to the corresponding quarter of 2005, primarily due to the Partnership’s November 2005 Javelina acquisition, which contributed $4.9 million.  We also experienced a $2.2 million increase in East Texas related to our new Carthage facility and the Blocker gathering system, as well as a $0.6 million increase in Other Southwest due to the addition of new compressors in late 2005 and 2006.

Equity in earnings from unconsolidated affiliates.  Equity in earnings from unconsolidated affiliates is primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC.  During the nine months ended September 30, 2006, our equity in earnings from unconsolidated affiliates increased $3.2 million relative to the comparable period in 2005. The increase was primarily due to our 2006 results including Starfish for nine months, compared to just three months in 2005.

Interest Expense and Amortization of Deferred Financing Costs (a component of interest expense).  Interest and amortization expense increased $24.3 million, or 166%, during the nine months ended September 30, 2006, relative to the comparable period in 2005, primarily due to increased debt levels resulting from the financing of our 2005 acquisitions and higher interest rates. The increase in the amortization of deferred financing costs in 2006, relative to the comparable period in 2005, is attributable to costs associated with our debt refinancing completed in the fourth quarter of 2005. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Miscellaneous Income.  Miscellaneous income increased by $7.5 million during the nine months ended September 30, 2006, relative to the comparable period in 2005, due almost entirely to the Partnership recognizing a $7.4 million income from insurance recoveries, net of Starfish insurance premiums, recovered from damages from Hurricane Rita.

Texas Margin Tax.  Texas passed a margin tax law that subjects the Partnership to an entity-level tax on the portion of its income that is generated in Texas. We recorded a deferred tax liability of $0.7 million in the second quarter of 2006, related to the Partnership’s temporary differences that are expected to reverse in future periods.

Liquidity and Capital Resources

MarkWest Hydrocarbon Standalone

Our primary source of liquidity to meet operating expenses and fund capital expenditures is cash flow from operations, principally from the marketing of NGL and quarterly distributions received from MarkWest Energy Partners.  Based on current volume, price and expense assumptions, we expect cash flow from operations and distributions from the Partnership to fund our operations and capital expenditures in 2006.  Most of our future capital expenditures are discretionary.

As of September 30, 2006, we owned 89% of the general partner of MarkWest Energy Partners, excluding interests held by certain employees and directors but deemed owned by the Company through the Participation Plan.  On October 13, 2006, the Company completed the purchase of a 0.5% interest in the general partner.  This purchase resulted in an increase in our ownership level in the general partner to 90%.  The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights.  The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached.  Specifically, they entitle us to receive 13% of all cash distributed in a quarter after each unit has received $0.55 for that quarter; 23% of all cash distributed after each unit has received $0.625 for that quarter; and 48% of all cash distributed after each unit has received $0.75 for that quarter.  For the nine months ended September 30, 2006, we received $6.4 million in distributions from our limited units and $7.1 million from our general partner interest, of which $6.3 million represented payments on incentive distribution rights.

Cash flows generated from our NGL marketing and natural gas supply operations are subject to volatility in energy prices, especially prices for NGLs and natural gas.  Our cash flows are enhanced in periods when NGL prices are high relative to the price of the natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia.  Conversely, they are reduced in periods when the NGL prices are low relative to the price of natural gas we purchase to satisfy such contractual arrangements.  Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep-whole” the producers for

41

the energy content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas.  Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts.  Periodically, natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, and the cost of keeping the producer “whole” can result in operating losses.

Debt

In October 2004 the Company entered into a $25.0 million senior credit facility with a term of one year.  The $25.0 million revolving facility has a variable interest rate based on the base rate or the London Inter Bank Offering Rate (“LIBOR”), as discussed below.  In October, November and December 2005, the Company entered into the first, second and third amendment to the credit agreement.  The first amendment to the credit facility extended the term of the original agreement to November 15, 2005.  The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million is committed to a letter of credit, leaving $10.0 million available for revolving loans.  The second amendment also extended the term of the revolving credit to December 30, 2005.  The third amendment extended the term of the revolving credit to January 31, 2006, and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving $7.5 million available for revolving loans. On January 31, 2006, the Company entered into the first amended and restated credit agreement which reinstated the maximum lending limit of $25.0 million for a one year term.  On August 18, 2006, the Company entered into the second amended and restated credit facility which increased the size of the facility from $25 million to $55 million, increasing the term of the agreement to three years and allowing the flexibility for MarkWest Hydrocarbon to directly invest in additional units of MarkWest Energy Partners to fund future growth opportunities.

The Company Credit Facility bears interest at a variable interest rate, plus basis points.  The variable interest rate typically is based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate.  The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75% for Eurodollar Rate loans.  The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.

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

At September 30, 2006, we had no debt outstanding on the Company Credit Facility and $28.0 million available for borrowing.

We spent $0.3 million for capital expenditures for the year ending December 31, 2005.  We have budgeted $0.8 million for 2006, principally for computer hardware and software.  We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners and projected cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future.  Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

MarkWest Energy Partners

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

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”). It 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 that can be repaid at any time without penalty. Under certain circumstances, the Partnership Credit Facility can be increased from $250 million to $450 million. 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

42

those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Partnership’s Consolidated Senior 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”). Borrowings under the Partnership Credit Facility were used to finance, in part, the Javelina acquisition discussed above. On September 30, 2006, the available borrowing capacity under the Partnership Credit Facility was $236.7 million.

Cash generated from operations, borrowings under the Partnership Credit Facility and funds from the Partnership’s private and public equity offerings are its primary sources of liquidity. The timing of the Partnerships efforts to raise equity has been influenced by its failure to file in a timely manner its Annual Report on Form 10-K for the year ended December 31, 2004, and its quarterly report on Form 10-Q for the quarter ending March 31, 2005. In order to raise capital through a public offering with the SEC, they will not have the ability to incorporate by reference information from its future filings into a new registration statement until October 11, 2006. To raise additional capital through public debt or equity offerings, the Partnership is required to file a Form S-1, which is a long-form type of registration statement.

At September 30, 2006, the Partnership and its subsidiary MarkWest Energy Finance Corporation also have two senior note offerings with debt outstanding of $225.0 million at a fixed rate of 6.875%, which will mature in November, 2014 (the “2014 Senior Notes”) and senior notes of $196.8 million, net of an original issue discount of $3.2 million, at a fixed rate of 8.5%, due in July 15, 2016 (the “2016 Senior Notes”).   The proceeds from these notes were used to pay down the Partnership’s outstanding debt under its credit facility in October 2004 and July 2006, respectively. 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 2016 Senior Notes will mature on July 15, 2016, and interest is payable each July 15 and January 15, commencing January 15, 2007. The Partnership closed this private placement on July 6, 2006. The net proceeds from the private placement were approximately $191.2 million, after deducting the initial purchasers’ discounts and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering to repay a portion of the term debt under the Partnership Credit Facility. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc. and Wachovia Capital Markets, LLC, are lenders under the Partnership Credit Facility.

The indenture governing the 2014 Senior Notes and the 2016 Senior Notes limits the activity of the Partnership and its restricted subsidiaries. The provisions of such indenture place limits on 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.

On October 20, 2006, the Partnership and its subsidiary MarkWest Energy Finance Corporation completed their private placement of an additional $75.0 million in aggregate principal amount of 8 1¤2% senior notes due in 2016 to qualified institutional buyers. The 2016 Senior Notes are being offered as additional debt securities under an indenture pursuant to which we have issued $200.0 million in aggregate principal amount of our 8 1/2% Senior Notes due 2016. The 2016 Senior Notes will mature on July 15, 2016, and interest is payable on each July 15 and January 15, commencing January 15, 2007. The net proceeds from the private placement were approximately $74.5 million, after deducting the initial purchasers’ discounts and legal, accounting and other transaction expenses. The Partnership used a portion of the net proceeds from the offering to retire the term debt under the Partnership Credit Facility, and will use the remaining net proceeds to fund capital expenditures for general corporate purposes.

On July 6, 2006, the Partnership completed its underwritten public offering of 3.0 million common units (the “Common Unit Offering”) at a public offering price of $39.75 per common unit. In addition, on July 12, 2006, the Partnership completed the sale of an additional 300,000 common units to cover over-allotments in connection with the Common Unit Offering. The sale of units resulted in total gross proceeds of $131.2 million, and net proceeds of $127.3 million after the underwriters’ commission and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering,

43

which includes a capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to retire a portion of the term debt under the Partnership Credit Facility.

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

The Partnership revised its budget as of September 30, 2006, to $146.2 million for capital expenditures, exclusive of any acquisitions. As of September 30, 2006, the Partnership has $91.1 million remaining in its budget, consisting of $89.9 million for expansion capital and $1.2 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets, or facilitate an increase in volumes within its operations, whether through construction or acquisition. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

Cash Flows

	Nine months ended September 30,
	2006			2005
	(in thousands)
Net cash provided by operating activities	$	130,269		$	23,282
Net cash used in investing activities	(68,583		)	(91,997		)
Net cash provided by (used in) financing activities	(45,854		)	58,029

Net cash provided by operating activities increased $107.0 million during the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005. This increase resulted primarily from an increase in net income of $16.5 million, an increase in the non-controlling interest in net income of the Partnership of $44.7 million, an increase in our unrealized gains on derivative instruments of $9.6 million and increases in the changes of our operating assets and liabilities totaling $26.7 million.  This change in operating assets and liabilities was primarily the result of an increase in cash provided by the change in receivables of $55.4 million due to seasonal and collection efforts offset by a decrease in cash provided by the change in accounts payable of $45.7 million.

Net cash used in investing activities decreased by $23.4 million during the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005, primarily due to our March 2005 investment of $41.7 million for a 50% non-operating interest in Starfish.

Net cash used in financing activities increased $103.9 million during the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005. This resulted primarily from additional borrowings of $85.5 million in the prior year’s comparable period.  In the nine months ended September 30, 2006 we had net pay downs of $131.9 million primarily as a result of the Partnership’s equity offering proceeds of $123.4 million.  Additionally, distributions to unitholders increased to $30.2 million in the first three quarters of 2006, from $19.4 million in the same period of 2005.

Off-Balance Sheet Arrangements

Other than facility and equipment leasing arrangements, we do not engage in off-balance sheet financing activities.

Matters Influencing Future Results

During August and September 2005 Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. Operations of our unconsolidated affiliate, Starfish Pipeline Company, were nominally impacted by Hurricane Katrina but were significantly impacted by Hurricane Rita. While Starfish has substantially returned to normal operations, several sections of the system have not been fully repaired and returned to operation. Until necessary repairs are completed, Starfish will not be able to return fully to normal operations, which will have a continuing impact on our net income. We have recorded $10.4 million in accrued insurance recoveries with respect to our property loss claims, and anticipate continued recovery for expenses and losses incurred as repairs proceed.

The loss to both offshore and onshore assets resulting from Hurricane Rita has led to substantial insurance claims within the oil and gas industry. Along with other industry participants, we have seen our insurance costs increase substantially within this region as a result. We have renewed our insurance coverage relating to Starfish during the second

44

quarter and mitigated a portion of the cost increase by reducing our coverage and adding a broader self-insurance element to our overall coverage.

As part of its ongoing operation of the Appalachia Liquids Pipeline System (ALPS) pipeline, our affiliate MarkWest Energy Appalachia, L.L.C. (MEA) has continued to perform pipeline integrity assessments and implement an in-line inspection program.  Preliminary data from a four mile section of its in-line inspection program identified areas for investigation and corrective action. MEA has presently shutdown the line while additional assessment and appropriate remedial action is undertaken to address these concerns. MEA will truck the natural gas liquids from the Maytown plant to the Siloam fractionation facility while the line is shutdown.  The ALPS inspections and operations will continue to be reviewed as continuing and final in-line inspection and assessment data is received.

MarkWest Hydrocarbon, Inc. is a corporation for federal income tax purposes. As such, our federal taxable income is subject to tax at a maximum rate of 35.0% under current law and a blended state rate of 3.5%, net of Federal benefit. We expect to have future taxable income allocated to us as a result of our investment in the Partnership.

We currently have a federal net operating loss carryforward of $13.2 million as of September 30, 2006. We estimate that our net operating loss carryforwards will be fully utilized to offset federal taxable income in 2006. As a result, the amount of money available to provide dividends to our stockholders will decrease after we utilize all of our net operating loss carryforward.

We are currently evaluating the impact of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes.

Critical Accounting Policies

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Preparation of these statements requires management to make significant judgments and estimates. Some accounting policies have a significant impact on amounts reported in these financial statements. A summary of significant accounting policies and a description of accounting policies that are considered critical may be found in our Annual Report on Form 10-K for the period ending December 31, 2005, in Note 2 of the Notes to the Consolidated Financial Statements, and in the Critical Accounting Policies section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Recent Accounting Pronouncements

In February 2006 the Financial Accounting Standards Board (“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.

In June 2006 the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a “more likely than not” recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of FIN 48.

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In September 2006 the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157”). SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years, with early adoption permitted.  The Company has not yet determined the impact, if any, the implementation of SFAS No. 157 may have on the condensed consolidated financial statements of the Company.

In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB 108 is effective for the first annual period ending after November 15, 2006. The Company is currently evaluating the impact of adopting SAB 108 on its financial statements.

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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) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that we enter into derivative instruments, we may be prevented from realizing the benefits of favorable price changes in the physical market. We are similarly insulated, however, against unfavorable changes in such prices.

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

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, entered into swaps and future sales agreements to manage frac spread risk. These derivative instruments are marked to market.

The following tables summarize the derivative positions specific to MarkWest Hydrocarbon’s Standalone segment at September 30, 2006:

Swaps	Contract Period	Fixed Price (1)		Fair Value
				(in thousands)
Crude Oil - 642 Bbl/d	Apr-Jun 2007	$	67.00	$	(55	)
Crude Oil - 313 Bbl/d	Apr-Jun 2007	80.21		336
Iso Butane - 6,532 Gal/d	Oct 2006	1.12		(14		)
Iso Butane - 6,750 Gal/d	Nov 2006	1.12		(18		)
Iso Butane - 8,492 Gal/d	Dec 2006	1.12		(21		)
Iso Butane - 2,503 Gal/d	Dec 2006	1.34		11
Iso Butane - 2,371 Gal/d	Jan 2007	1.35		10
Iso Butane - 6,184 Gal/d	Jan-Mar 2007	1.16		(28		)
Iso Butane - 3,007 Gal/d	Feb-Mar 2007	1.35		24
Iso Butane - 1,806 Gal/d	Mar 2007	1.28		4

47

Natural Gasoline - 13,065 Gal/d	Oct 2006	1.39	19
Natural Gasoline - 13,500 Gal/d	Nov 2006	1.39	11
Natural Gasoline - 8,492 Gal/d	Dec 2006	1.37	(4		)
Natural Gasoline - 16,647 Gal/d	Dec 2006	1.50	56
Natural Gasoline - 8,419 Gal/d	Jan 2007	1.59	43
Natural Gasoline - 12,446 Gal/d	Jan-Mar 2007	1.37	(63		)
Natural Gasoline - 10,034 Gal/d	Feb-Mar 2007	1.59	94
Natural Gasoline - 4,387 Gal/d	Mar 2007	1.62	26
Normal Butane - 19,597 Gal/d	Oct 2006	1.10	(19		)
Normal Butane - 20,250 Gal/d	Nov 2006	1.10	(30		)
Normal Butane - 25,476 Gal/d	Dec 2006	1.10	(38		)
Normal Butane - 10,281 Gal/d	Dec 2006	1.30	48
Normal Butane - 8,639 Gal/d	Jan 2007	1.29	33
Normal Butane - 18,891 Gal/d	Jan-Mar 2007	1.13	(42		)
Normal Butane - 10,712 Gal/d	Feb-Mar 2007	1.29	83
Normal Butane - 5,839 Gal/d	Mar 2007	1.28	23
Propane - 62,710 Gal/d	Oct 2006	0.93	(47		)
Propane - 13,548 Gal/d	Oct 2006	1.10	63
Propane - 64,800 Gal/d	Nov 2006	0.93	(74		)
Propane - 23,667 Gal/d	Nov 2006	1.09	89
Propane - 3,500 Gal/d	Nov 06-Feb 07	1.05	31
Propane - 81,523 Gal/d	Dec 2006	0.93	(104		)
Propane - 174,342 Gal/d	Dec 2006	1.11	755
Propane - 171,226 Gal/d	Jan 2007	1.12	734
Propane - 71,516 Gal/d	Jan-Mar 2007	0.96	(32		)
Propane - 133,429 Gal/d	Feb 2007	1.10	462
Propane - 23,797 Gal/d	Feb-Mar 2007	1.18	288
Propane - 25,806 Gal/d	Mar 2007	1.13	133
			$	2,787

Fixed Physical (Forward Purchases)	Contract Period		Fixed Price (1)		Fair Value
					(in thousands)
Natural Gas - 9,677 MMBtu/d		Oct 2006	$	7.19	$	(859	)
Natural Gas - 11,000 MMBtu/d		Nov 2006	6.48		(229		)
Natural Gas - 6,371 MMBtu/d		Jan 2007	10.41		448
Natural Gas - 7,143 MMBtu/d		Feb 2007	10.76		505
					$	(135	)
Current-Total MarkWest Hydrocarbon Standalone					$	2,652

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

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

	Three months ended September 30,						Nine months ended September 30,
	2006			2005			2006			2005
Realized losses - revenue	$	(255	)	$	(786	)	$	(255	)	$	(2,086	)
Unrealized gains - revenue	10,306			5			2,652			739
Other comprehensive income - changes in fair value	—			1,292			—			1,963
Other comprehensive losses- settlement	—			(900		)	—			(1,768		)

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	September 30, 2006			December 31, 2005
Fair value of derivative instruments – current asset	$	4,329		$	—
Fair value of derivative instruments – current liability	(1,677		)	—

The Company entered into the following derivative positions subsequent to September 30, 2006:

Swaps	Contract Period	Fixed Price
Propane - 40,417 Gal/d	Jan 2007	$	0.97
Propane - 45,314 Gal/d	Feb 2007	0.96
Normal Butane - 12,379 Gal/d	Jan 2007	1.14
Normal Butane - 13,879 Gal/d	Feb 2007	1.12
IsoButane - 3,860 Gal/d	Jan 2007	1.16
IsoButane - 4,328 Gal/d	Feb 2007	1.16
Natural Gasoline - 9,337 Gal/d	Jan 2007	1.34
Natural Gasoline - 10,468 Gal/d	Feb 2007	1.33

Fixed Physical (Forward Purchases)	Contract Period	Fixed Price (1)
Natural gas - 122,500 MMBtu/d	Jan 2007	$	8.95
Natural gas - 200,000 MMBtu/d	Feb 2007	9.07

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

MarkWest Energy Partners

The Partnership’s primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude oil.  Swaps and futures contracts may allow the Partnership to reduce volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership’s sales of physical product.  While we largely expect our realized derivative gains and losses to be offset by increases or decreases in the value of our physical sales, we will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative positions that will have no offset.  The volatility in any given period related to unrealized gains or losses can be significant to the overall results of the Partnership, however, we ultimately expect those gains and losses to be offset when they become realized.

The following tables summarize the current derivative positions specific to MarkWest Energy Partner’s segment at September 30, 2006:

Swaps	Contract Period	Fixed Price (1)		Fair Value
				(in thousands)
Propane - 39,662 Gal/d	Oct 2006	$	1.09	$	150
Propane - 5,000 Gal/d	Oct-Dec 2006	1.08		52
Normal Butane - 9,413 Gal/d	Oct 2006	1.20		34
Natural Gasoline - 16,990 Gal/d	Oct 2006	1.56		150
IsoButane - 7,981 Gal/d	Oct 2006	1.25		31
Ethane - 87,666 Gal/d	Oct 2006	0.61		149
Ethane - 50,000 Gal/d	Jan-Mar 2007	0.78		670
Crude Oil - 435 Bbl/d	Oct-Dec 2006	61.57		(112		)
Crude Oil - 250 Bbl/d	Jan-Sep 2007	65.30		(164		)
Crude Oil - 140 Bbl/d	Jan-Sep 2007	74.10		233
Natural Gas - 13,888 MMBtu/d	Oct 2006	6.33		(1,207		)
				$	(14	)

Basis Swaps	Contract Period	Fair Value
		(in thousands)
Natural Gas	Oct 2006	$	(2	)
Natural Gas	Nov 2006-Sep 2007	1
		$	(1	)

Options	Contract Period	Floor		Fair Value
				(in thousands)
Ethane - 50,000 Gal/d	Apr-Jun 2007	$	0.65	$	384
Ethane - 50,000 Gal/d	Jul-Sep 2007	0.65		419
				$	803

49

Collars (Forward Sales)	Contract Period		Floor (1)		Cap (1)		Fair Value
							(in thousands)
Propane - 20,000 Gal/d		Oct-Dec 2006	$	0.90	$	0.99	$	(20	)
Propane - 10,000 Gal/d		Oct-Dec 2006	0.97		1.15		34
Propane - 23,000 Gal/d		Jan-Mar 2007	1.05		1.28		228
Propane - 30,000 Gal/d		Apr-Jun 2007	0.96		1.16		228
Propane - 30,000 Gal/d		Jul-Sep 2007	0.97		1.16		251
Ethane - 22,950 Gal/d		Oct-Dec 2006	0.65		0.80		86
Crude Oil - 955 Bbl/d		Oct-Dec 2006	57.00		66.59		(95		)
Crude Oil - 78 Bbl/d		Oct-Dec 2006	67.50		77.30		30
Crude Oil - 1,105 Bbl/d		Jan-Sep 2007	69.08		82.43		1,327
Natural Gas - 1,575 MMBtu/d		Oct 2006	8.50		10.05		242
Natural Gas - 1,575 MMBtu/d		Nov 2006-Mar 2007	9.00		12.50		656
Natural Gas - 1,500 MMBtu/d		Jan-Mar 2007	7.25		10.25		(124		)
Natural Gas - 1,900 MMBtu/d		Jan-Sep 2007	7.46		10.20		592
							$	3,435
Current-Total MarkWest Energy Partners							$	4,223

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

The following tables summarize the non-current derivative positions specific to MarkWest Energy Partner’s segment at September 30, 2006:

Swaps	Contract Period	Fixed Price		Fair Value
				(in thousands)
Crude Oil - 250 Bbl/d	Oct-Dec 2007	$	65.30	$	(82	)
Crude Oil - 140 Bbl/d	Oct-Dec 2007	74.10		61
				$	(21	)

Basis Swaps	Contract Period	Fair Value
		(in thousands)
Natural Gas	Oct 2007	$	(3	)

Options	Contract Period	Floor		Fair Value
				(in thousands)
Ethane - 50,000 Gal/d	Oct-Dec 2007	$	0.65	$	431

Collars (Forward Sales)	Contract Period		Floor (1)	Cap (1)		Fair Value
						(in thousands)
Crude Oil - 1,105 Bbl/d		Oct-Dec 2007	69.08	$	82.43	$	398
Crude Oil - 1,476 Bbl/d		Jan-Mar 2008	69.76	79.01		492
Crude Oil - 275 Bbl/d		Jan-Dec 2008	64.95	73.10		(5		)
Crude Oil - 275 Bbl/d		Jan-Dec 2008	64.00	74.85		15
Crude Oil - 1,473 Bbl/d		Apr-Jun 2008	69.48	78.66		469
Crude Oil - 1,437 Bbl/d		Jul-Sep 2008	68.90	78.32		427
Crude Oil - 1,473 Bbl/d		Oct-Dec 2008	68.41	77.85		411
Crude Oil - 1,550 Bbl/d		Jan-Dec 2009	63.04	70.91		(432		)
Natural Gas - 1,900 MMBtu/d		Oct-Dec 2007	7.46	10.20		139
Natural Gas - 1,500 MMBtu/d		Jan-Mar 2008	8.00	11.29		118
Propane - 30,000 Gal/d		Oct-Dec 2007	0.98	1.18		275
						$	2,307
Non-current-Total MarkWest Energy Partners						$	2,714

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(1) - A weighted average is used for certain positions.

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

	Three months ended September 30,						Nine months ended September 30,
	2006			2005			2006			2005
	(in thousands)
Realized losses - revenue	$	(1,719	)	$	(273	)	$	(1,656	)	$	(482	)
Unrealized gains - revenue	14,389			6			7,665			68
Other comprehensive income - changes in fair value	—			111			—			358
Other comprehensive loss - settlement	—			(302		)	—			(482		)

	September 30, 2006			December 31, 2005
Fair value of derivate instruments – current asset	$	5,947		$	—
Fair value of derivate instruments – noncurrent asset	3,236			—
Fair value of derivate instruments – current liability	(1,724		)	(728		)
Fair value of derivate instruments – noncurrent liability	(522		)	—

The Partnership entered into the following derivative positions subsequent to September 30, 2006:

Collars (Forward Sales)	Contract Period	Floor (1)		Cap (1)
Crude Oil - 925 Bbl/d	2008	$	65.00	$	68.78
Crude Oil - 1,375 Bbl/d	2009	64.35		68.47

Swaps	Contract Period	Fixed Price (1)
Crude Oil - 600 Bbl/d	2007	$	64.77

Basis Swaps	Contract Period
Natural gas basis PEPL-ANR - 9,000 MMBtu/d	Nov 2006 - Oct 2007

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

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Item 4. Controls and Procedures

In connection with the preparation of this quarterly report on Form 10-Q, our senior management, with participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2006, pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Act”). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of September 30, 2006, as a result of the material weaknesses in our internal control over financial reporting, our disclosure controls and procedures were ineffective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and to ensure that information required to be disclosed by us in the reports that we file under the Act is accumulated and communicated to management, including our certifying officers, as appropriate, to allow timely decisions regarding required disclosures.

Throughout the first, second and third quarters of 2006 we have adopted remedial measures to address the deficiencies in our internal controls that were identified on December 31, 2005 and remained in effect on September 30, 2006.

Internal Control Environment.  In connection with management’s assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed, the presence of an ongoing material weakness related to our internal control environment. Specifically, our control environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement.

In order to remediate this material weakness, we have implemented and standardized the following processes and procedures, which were initiated and/or completed between July 2005 and September 2006:

·We formalized the monthly account reconciliation process for all balance sheet accounts and have implemented a formal review of reconciliations by our business unit accounting management.

·We established a compliance office focused on control deficiency identification and remediation, i.e., purchasing controls, revenue recognition controls and application and spreadsheet change controls that performs ongoing internal control evaluation and assessment and works actively with the process owners in developing appropriate remediation of control deficiencies.

·We conducted an entity-level risk assessment, established an internal audit plan and began to execute that internal audit plan. Results are reported directly to our audit committee.

·We enhanced entity-level controls through the implementation of significant new controls.

·We strengthened our disclosure review committee charter to solicit and review input from management personnel throughout the Partnership regarding possible instances of fraud or significant events requiring disclosure.

·We implemented a technical accounting issues forum to address non-routine transactions and the use of critical estimates and judgment.

·We initiated a revised Code of Conduct, ethics and anti-fraud training program that we began to deliver to all employees in the second quarter of 2006.

·We initiated a detailed review and re-documentation of all of our internal control processes and have undertaken significant internal control design changes to ensure that all internal control objectives are met.

·We initiated the consolidation of substantially all accounting functions in the Denver office to provide enhanced communication and reporting capability.

In addition, during the third quarter of 2006, we have:

·Enhanced employee awareness of our Code of Conduct, ethics and anti-fraud policies through the training program that we  began in the second quarter and delivered to substantially all employees in the second and third quarters of 2006. This training included heightened awareness of the ethics hotline availability and access options.

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·Completed a detailed review and re-documentation of all of our internal control processes and implemented significant internal control design changes to ensure that all internal control objectives are met.

·Consolidated substantially all accounting functions in the Denver office to provide enhanced communication and reporting capability.

·Initiated and made substantial progress on management’s annual assessment of the effectiveness of internal controls.

Risk Management and Accounting for Derivative Financial Instruments.  In connection with management’s assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed, as of December 31, 2005, the presence of an additional material weakness related to our risk management and accounting for derivative financial instruments. We did not have adequate internal controls and processes in place to support our management’s assertions with respect to the completeness, accuracy and validity of commodity transactions. The design of internal controls over commodity transactions did not support the independent validation of data or control and review of transaction activity.

In particular, personnel responsible for executing and entering transactions into commodity accounting systems also had duties that were not compatible with transaction execution and entry.  In order to remediate this material weakness, we added the following personnel in July 2005, and January and June 2006, respectively:

·Vice President of Risk and Compliance, to oversee and ensure improvements in our commodity transaction verification and monitoring capabilities.

·Director of Risk Management and staff to establish appropriate verification and monitoring activities associated with our commodity transactions.

·Credit Manager, to establish more robust monitoring and reporting processes around our credit concentrations and risk.

In order to remediate this material weakness, we have implemented and standardized the following processes and procedures, which were initiated and/or completed between October 2005 and June 2006:

·We segregated our front-office (the transaction personnel), mid-office (the controllers), and back-office (the accountants) processes related to our financial commodity transactions and our physical trading activities.

·We have enhanced our risk management policies and procedures related to the review and approval of material purchase or sale contracts that may meet the definition of derivatives.

·We have enhanced our financial analysis around commodity transactions and our reporting to executive management and the board of directors.

·We moved the responsibility for credit risk management to the mid-office and established enhanced procedures for the management of credit risk.

·We have initiated and made substantial progress on management’s assessment of the effectiveness of internal controls related to commodity transacting and risk management.

In addition, during the third quarter of 2006, we have:

·      Initiated the enhancement of our risk management and credit policies to more clearly define the oversight roles and define the relationships and responsibilities of all involved parties.  These policies were approved at the October, 2006 Board of Directors meeting.

Compensating Procedures and Processes. In addition, we have applied compensating procedures and processes as necessary to ensure the reliability of our financial reporting. Such additional procedures included detail management review of our account reconciliations for all accounts in all business units and multiple-level management review of account reconciliations for all accounts in all business units. Accordingly, management believes, based on its knowledge, that (i) this report does not contain any untrue statement of a material fact that would make the statements misleading; (ii) this report does not omit any material fact, the omission of which would make the statements misleading, in light of the circumstance under which they were made with respect to the period covered by this report and (iii) the financial statements, and other financial information included in this report, fairly present in all material respects our financial condition, results of operations and cash flows as of, and for, the periods presented in this report.

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PART II—OTHER INFORMATION

Item 1.Legal Proceedings

In the ordinary course of business, the Company is subject to a variety of risks and disputes normally 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, 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, and the cases were consolidated into Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137.

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 explosion and 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 underway following the remand back to state court. The trial is scheduled to begin February 5, 2007.

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.

In late June 2006 a Notice of Probable Violation and Proposed Civil Penalty (NOPV) was issued by OPS to both MarkWest Hydrocarbon and the unaffiliated owner of the pipeline, with a proposed penalty in the aggregate amount of $1,070,000. OPS has placed the matter in abeyance until further notice pending further discussions and exploration of appropriate settlement and resolution of the NOPV.

Related to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership have 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 related to the pipeline incident. These include the Company’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred for transporting the liquids while the pipeline was out of service; the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). 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 it is 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 the 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. Discovery in the action is continuing.

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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. On October 12th, 2006, the Sixth Circuit affirmed the District Court’s previous grant of Summary Judgment against Ross Bros. Construction.

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.

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Item 6. Exhibits

10.1+	Construction, Operation and Gas Gathering Agreement dated as of September 21, 2006 between MarkWest Western Oklahoma Gas Company LLC and Newfield Exploration Mid-Continent Inc.
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.

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

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SIGNATURES

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

	MarkWest Hydrocarbon, Inc.
	(Registrant)
Date:  November 6, 2006	/s/ FRANK M. SEMPLE
	Frank M. Semple
	Chief Executive Officer
Date:  November 6, 2006	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President and
	Chief Financial Officer

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