10-Q

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%.

13

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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EX-10.1

Exhibit 10.1

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL
TREATMENT FOR THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL
HAS BEEN SEPARATELY FILED WITH THE SECURITIES AND EXCHANGE COMMISSION,
AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH
TWO ASTERISKS (**).

CONSTRUCTION, OPERATION AND
GAS GATHERING AGREEMENT

Entered into by and between

Newfield Exploration Mid-Continent Inc.,
as Producer

and

MarkWest Western Oklahoma Gas Company, L.L.C.,
as Gatherer

Effective as of the 21st day of September, 2006.

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TABLE OF CONTENTS

		Page
I.	Definitions	2
II.	Scope of Agreement	6
III.	Services Provided by Gatherer	7
IV.	Construction of the System and Acquisition and Sale of Producer’s System	8
V.	Receipt and Delivery of Gas	11
VI.	Operational Imbalance and Cash Balancing	14
VII.	Receipt Pressures and Remedies	16
VIII.	Measurement	19
IX.	Gas Quality and Specifications	20
X.	Gathering, Compression, Treating Fees, Line Loss and Fuel Charge	22
XI.	Billing, Payment and Reporting	23
XII.	Taxes	24
XIII.	Control, Possession, Title and Additional Indemnification	25
XIV.	Acquisitions	26
XV.	Representations and Warranties	28

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XVI.	Force Majeure	29
XVII.	Term	30
XVIII.	Assignments and Sale of Gatherer’s System	31
XIX.	Notices	32
XX.	Guaranty by Gatherer’s Parent Entity	34
XXI.	Miscellaneous	34

ii

CONSTRUCTION, OPERATION AND GAS GATHERING AGREEMENT

THIS CONSTRUCTION, OPERATION AND GAS GATHERING AGREEMENT (this “Agreement”) is made and entered into as of this 21st day of September 2006 (the “Effective Date”), by and between Newfield Exploration Mid-Continent Inc., hereinafter referred to as “Producer”, and MarkWest Western Oklahoma Gas Company, L.L.C.  hereinafter referred to as “Gatherer.” (Producer and Gatherer may at times be referred to herein as a “Party” or, collectively, as “Parties”).

W I T N E S S E T H

WHEREAS, Producer owns or controls certain Gas to be produced and saved from the wells, lands, leaseholds and other sources within the Woodford Shale Project Area (as defined below);

WHEREAS, Producer owns, operates, and maintains certain gas gathering facilities in the Woodford Shale Project Area;

WHEREAS, Producer desires Gatherer to acquire and take over the expansion, operation, maintenance, and control of Producer’s System;

WHEREAS, Producer desires that Gatherer construct, and Gatherer intends to cause to be constructed, gas gathering facilities to receive and gather Producer’s Gas at the Receipt Points and deliver Producer’s Gas to Producer or for Producer’s account at the Delivery Points under the terms and conditions herein.

WHEREAS, Gatherer intends to acquire Producer’s System and to further construct and install additional gas gathering, compression, Treating, dehydration and related facilities, in Woodford Shale Project Area ; and

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein, Gatherer and Producer hereby agree as follows:

Article I.
DEFINITIONS

Except as otherwise provided, the following terms, when capitalized, whether in the singular, plural or possessive, shall have the meaning set forth below:

1.1           “Actual Costs” shall mean the costs and expenses recorded in a Party’s records, in accordance with GAAP as defined below.

1.2           “BTU” shall mean British Thermal Unit, which is the quantity of heat required to raise the temperature of one (1) pound avoirdupois of pure water from fifty-eight and five tenths degrees Fahrenheit (58.5°F) to fifty-nine and five tenths degrees Fahrenheit (59.5°F) at

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a pressure of fourteen and six hundred and ninety-six thousandths pounds per square inch absolute (14.696 psia).

1.3           “Business Day” shall mean the days of a week excluding weekends, federal holidays and any additional days on which federal banks are not open for business.

1.4           “Cash Flow” shall mean the sum of the monthly revenues from the System less all Operating Expenses attributable to the System recorded in accordance with GAAP.

1.5           “Commitment Area” shall mean the Woodford Shale Project Area (as defined below).

1.6           “Day” shall mean a period of twenty-four (24) consecutive hours which shall commence for operational issues at 9:00 o’clock a.m. Central Standard Time on one calendar day and end at 9:00 o’clock a.m. Central Standard Time on the following calendar day; and, for any other issues (including, but not limited to, non-operational contract issues), such twenty-four (24) consecutive hour period shall commence at 12:01 a.m. Central Standard Time on one calendar day and end at 12:01 a.m. Central Standard Time on the following calendar day.

1.7           “Deemed Fuel,” “Deemed System Loss,” and “Measured Treating Fuel and Loss” shall have the meanings set forth in Article X and/or in Exhibit G herein.

1.8           “Delivery Points” shall mean the outlet flange of the measurement facilities at the points of interconnection between (A) Producer’s System and/or Gatherer’s System (some components of which are presently Producer’s System but will ultimately  become part of Gatherer’s System) and (B) the existing interstate and intrastate pipelines within the Commitment Area of the following entities and any of their related or affiliated persons or entities: **. The term “Delivery Points” shall have the same meaning with respect to any additional Pipeline Carriers, and shall apply to any other future delivery points on the System that Producer may designate within the Commitment Area.

1.9           “Fees” refers collectively to the “Gathering Fee,” “Compression Fee,” and “Treating Fee.” The terms “Gathering Fee,” “Compression Fee,” and “Treating Fee” shall have the meanings set forth in Article X and in Exhibit G.

1.10         “GAAP” shall mean U.S. generally accepted accounting principles.

1.11         “Gas” includes gas well gas produced from wells classified as gas wells by any governmental authority having jurisdiction, casinghead gas produced from oil wells so classified, and flash gas vaporized from crude oil and condensate therefrom after production.

1.12         “BTUs”, “Heating Content” or “Heating Value” shall mean the gross ideal heating value of and the number of BTUs measured in the Gas in accordance with GPA Standards 2145 & 2172 at Standard Base Conditions.

1.13         “Inferior Liquids” shall mean mixed crude oil, slop oil, salt water, nuisance liquids, and other liquids that condense in the System and are recovered by Gatherer from its System.

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1.14         Monthly Average Pressure (“MAP”) shall have the meaning set forth in Section 7.1 of this Agreement.

1.15         “MSCF” or “mscf” shall mean one thousand (1,000) Standard Cubic Feet of Gas at Standard Base Conditions.

1.16         “MMBTU” or “mmbtu” shall mean one million BTU (1,000,000 BTUs).

1.17         “Month” shall mean a calendar month.

1.18         “Net Book Value” shall mean the depreciated book value of the assets comprising the System as reflected in the books and records of the company that owns the System in accordance with GAAP.  The depreciation method used for calculating Net Book Value shall be twenty (20) years straight line with zero percent salvage value.

1.19         “Operating Expenses” shall mean normal direct operating expenses of the System, which term expressly excludes any payments imposed on Gatherer as a result of non-performance or delayed performance under this Agreement.

1.20         “Pipeline Carriers” means the following pipelines receiving Producer’s Gas at the Delivery Points: the interstate and intrastate pipelines of **, and any other interstate or intrastate pipeline receiving Producer’s Gas at any Delivery Point.

1.21         “Processing” shall mean the conversion of gaseous hydrocarbons from a natural gas stream into liquefied form (“Natural Gas Liquids” or “NGLs”), and/or the removal of NGLs from the gas, through refrigeration, absorption, adsorption, chemical means or other industry accepted processes.  Processing may be invoked for the purposes of reducing Heating Value of the natural gas stream for purposes of meeting pipeline specifications, or for economic benefit.  Processing does not include the recovery of NGLs through mechanical separation, filtering or coalescing.

1.22         “Producer’s Gas” shall include all Gas owned or controlled by Producer, or its wholly-owned or controlled subsidiaries, which is produced from Well(s) in which Producer is the Operator.  “Producer’s Gas” shall not include gas that is subject to pre-existing commitments as listed on Exhibit E or addressed herein.

1.23           “Producer’s System” shall mean those certain existing or later constructed facilities located within the Woodford Shale Project Area (as defined below) for the delivery, compression, gathering, measurement, Treating, and dehydration of Producer’s Gas during the term of this Agreement, and other related facilities, all as may be further expanded, constructed or added during the transitional period before Gatherer fully acquires and operates the entire System, as provided for in the subsequent provisions of this Agreement.

1.24         “Receipt Points” shall be the points located within the Commitment Area where Producer elects in its sole and reasonable discretion to deliver Producer’s Gas to Gatherer and where Gatherer may receive Producer’s Gas in accordance with the terms of this Agreement.  At Producer’s election, a Receipt Point for particular volumes of Producer’s Gas may be the

4

interconnection of Producer’s central production facilities with the System or may be at the interconnection with the System of Producer’s individual well separation equipment located downstream of Producer’s Wells.

1.25         “Section of Land” shall mean, and be comprised of, the lands within the geographical area designated by state governmental authority as being a “section” for purposes of describing real property.

1.26         “Standard Base Conditions” shall mean a pressure of fourteen and sixty five hundredths pounds per square inch absolute (14.65 psia) at a temperature of sixty degrees Fahrenheit (60°F).

1.27         “Standard Cubic Foot” shall mean the volume of gas contained in one cubic foot of space at Standard Base Conditions.

1.28         “System” shall mean all delivery, compression, gathering, measurement, Treating, Processing and dehydration facilities, and other related facilities constructed, acquired or used by Gatherer to fulfill its obligations under this Agreement with respect to Producer’s Gas.  “System” shall also be construed to include all of Gatherer’s delivery, compression, gathering, measurement, Treating, Processing, dehydration facilities, and other related facilities constructed by or used by Gatherer in connection with Gas received by Gatherer from other parties on pipelines contiguously connected to pipelines used by Gatherer in connection with Producer’s Gas.   Also for the purposes of Article XIV, “System” shall also be construed to include all of Gatherer’s associated and related gas gathering, gas purchase, gathering, compressor lease, equipment lease, gas sales, rights-of-way, easements, surface use lease, and real property agreements and/or contracts as well as all permits, imbalance positions, and working capital adjustments used in connection with the operation of the physical assets of the System.

1.29         “Treating” or “Treat” shall mean the removal of unwanted components from a natural gas stream, including, but not limited to, water, Hydrogen Sulfide (“H2S”), Carbon Dioxide (“CO2”), and/or Nitrogen (“N2”) by utilizing industry accepted processes including, but not limited to, mechanical separation, chemical reaction, adsorption and absorption.

1.30         “Well” shall mean any well productive of Gas, from any formations, which is now or hereafter completed within the Commitment Area and in which Producer owns an interest.  The commitments and obligations of Gatherer under this Agreement shall extend to and include all of Producer’s Gas from such a Well.

1.31         “Woodford Shale Project Area” means all of that area of Atoka, Coal, Hughes and Pittsburg Counties, Oklahoma, shown on Exhibit A.  The Woodford Shale Project Area, as such term is used in this Agreement, includes all lands shown in Exhibit A, whether inside or outside the bold-lined or bracketed areas shown on such Exhibit A.  The segments shown on Exhibit A relate to the development requirements set forth on Exhibit B and any other provisions of this Agreement which reference those segments.

5

Article II.
SCOPE OF AGREEMENT

2.1           Gatherer hereby agrees, at its sole cost and expense, to design, construct and acquire (to the extent not acquired as part of Producer’s System), and to maintain and operate (or cause others to construct, maintain and operate) all gathering pipelines, compression, dehydration and Treating equipment and related facilities required to enable Gatherer to fulfill and perform its obligations under this Agreement including, but not limited to, (a) Gatherer’s receipt of Producer’s Gas at the Receipt Points within the Commitment Area, (b) the delivery of a thermally equivalent quantity of Producer’s Gas less only Deemed Fuel, Deemed System Loss and Measured Treating Fuel and Loss in accordance with the terms of this Agreement and in accordance with the requirements of the Pipeline Carriers, and (c) the Treating of Producer’s Gas, if such Gas is treated in connection with this Agreement.

2.2           Gatherer shall have the sole responsibility for the construction, maintenance, and operation of the System consistent with performing its obligations under this Agreement.  Gatherer will extend the System, and may add to or remove components from the System, and operate the System in the manner Gatherer determines to be best, so long as such operations are consistent with both Gatherer’s performance of its obligations under this Agreement and all applicable laws, rules and regulations of governmental entities.  Gatherer shall operate the System or cause it to be operated, as the System may exist from time to time, in a manner consistent with general industry practice, but shall not be prevented thereby from being innovative or achieving cost efficiencies as it may deem necessary or desirable, so long as such actions are consistent with both Gatherer’s performance of its obligations under this Agreement and all applicable laws, rules and regulations of governmental entities.

2.3           Prior to the completion of all or portions of the System by Gatherer such that, following the purchase of Producer’s System, Gatherer can gather, compress, dehydrate, and if required, Treat Producer’s Gas delivered into such completed portion(s) of the System and connect such completed portions of the System to portions of Producer’s System, Producer may at its option construct, maintain, and operate (or may cause others to construct, maintain, and operate) pipelines and related facilities on Producer’s System to enable Producer’s Gas from the Wells to be delivered to pipelines owned and controlled by the Pipeline Carriers.  It is expressly understood and agreed that Producer has no obligation to construct any additional facilities for the enlargement of Producer’s System, nor does Producer have any obligation to drill any Wells and/or connect any future Wells to Producer’s System prior to incorporation into Completed Segments (as defined in 4.2 below), of Gatherer’s System; rather, all of those actions shall be left to the sole discretion of Producer.  However, prior to the completion of Gatherer’s System, Producer shall continue Producer’s operation and maintenance of Producer’s System, including Producer’s existing Treating facilities.

2.4           Producer and Gatherer understand and agree that the design and operation of Producer’s System by Producer, and the design and operation of Gatherer’s System by Gatherer shall be performed in such a manner as to allow Producer to meet its delivery and other commitments to Gatherer in accordance with the terms of this Agreement.

2.5          Subject to those existing dedications and contractual obligations owing to third parties as described in Exhibit E, which shall take priority over the provisions of this Section 2.5, and subject to the subsequent provisions of this Agreement which provide for the future termination of, or release of Wells from, this Agreement, Producer hereby commits all of

6

Producer’s Gas to this Agreement.  Producer’s oil and gas leases within the Commitment Area, whether now or hereafter acquired, shall be subject to the terms and obligations of this Agreement which terms shall run with the land, subject to Section 14.4.  Gatherer may record a recording memorandum of this Agreement in the real property records in the offices of the County Clerks for the applicable Counties where Producer’s Gas leasehold interests or Wells within the Commitment Area and any parts of the System are located, provided that such recording memorandum shall only disclose information that Producer has previously approved for inclusion in the recording memorandum.  Upon written request from Gatherer, but no more often than once each calendar year, Producer shall advise Gatherer of after-acquired leases and consent to further supplements to the recording memorandum be filed against those leases.  Notwithstanding the preceding provisions of this Section 2.5 and any other terms and provisions of this Agreement that might appear to be to the contrary, it is expressly understood and agreed that, as to additional leases, Wells and other assets that may be acquired by Producer after the effective date of this Agreement, such assets shall not be subject to this Agreement to the extent that  Producer acquires such assets subject to any then-existing contractual or other obligations or encumbrances that are inconsistent with the obligations of this Agreement.

Article III.
SERVICES PROVIDED BY GATHERER

3.1           Gatherer shall, at Gatherer’s sole cost and expense, acquire and/or install all facilities that are needed or required to perform Gatherer’s obligations under this Agreement, including, but not limited to, Gatherer’s receipt of all of Producer’s Gas delivered by Producer at the Receipt Points in accordance with the terms of this Agreement and the gathering and compression of all of Producer’s Gas to a pressure such that Producer’s Gas can be delivered at the Delivery Points into the pipelines owned and/or controlled by the Pipeline Carriers.  In order to maximize the value of Producer’s Gas, Gatherer and Producer shall continue to explore opportunities to participate in or otherwise support pipeline expansions by Pipeline Carriers and other pipeline companies. Producer and Gatherer will discuss the options to mutually determine which and to what extent, if any, pipeline expansions Producer and Gatherer may participate in.  It is expressly agreed that Gatherer is obligated under this Agreement to provide at Gatherer’s sole cost ** Delivery Points, with one (1) such Delivery Point being established for each of the ** Pipeline Carriers which are specifically named in the above definition of “Pipeline Carriers,” at locations to be reasonably designated by Producer on each of those pipelines.  At such time as Gatherer acquires Producer’s System or segments thereof, Gatherer shall maintain all then existing Delivery Points on such acquired portions of the System, and such existing Delivery Points and the **, shall satisfy the foregoing obligation of Gatherer to provide Delivery Points to the Pipeline Carriers.  The Parties agree that Gatherer shall provide up to ** Delivery Points on currently existing and/or future pipelines within the Commitment Area, at locations within the Commitment Area to be reasonably designated by Producer on such pipelines, at Gatherer’s sole cost and expense, but that any additional Delivery Points beyond ** referred to above will be at Producer’s cost and expense.  The Parties understand that if any additional Delivery Points beyond ** referred to above require that Producer’s Gas be compressed to in excess of a Monthly average of 1,100 psig to meet the Pipeline Carrier’s pressure requirements at the Delivery Points, then Producer’s Gas actually delivered to those Delivery Points will be subject to Compression Fees and Deemed Fuel during such Month for one additional stage of compression.

7

3.2           Gatherer shall install all facilities needed or required to dehydrate Producer’s Gas as necessary to cause Producer’s Gas to meet the water content specifications of the pipelines owned and/or controlled by the Pipeline Carriers.

3.3           Gatherer shall install all CO2 Treating facilities needed or required to remove CO2 such that the CO2 content in Producer’s Gas at the Delivery Points shall meet the specifications of the pipelines owned and/or controlled by the Pipeline Carriers, provided that the CO2 content in Producer’s Gas delivered to the Receipt Point(s) shall not exceed 10%.  Gatherer shall endeavor to maintain the average CO2 content in Producer’s Gas delivered to each Pipeline Carrier at levels below the specifications required by the Pipeline Carriers by blending Producer’s Gas with a high CO2 content with Gas with a low CO2 content per the provisions of Section 9.3.

3.4           It is expressly agreed that Gatherer will have no duty under this Agreement to Treat Producer’s Gas for the purpose of removing H2S or N2.

Article IV.
CONSTRUCTION OF THE SYSTEM AND ACQUISITION
AND SALE OF PRODUCER’S SYSTEM

4.1           Recognizing that time is of the essence with regard to the performance required under this Agreement, Gatherer shall construct, or cause to be constructed, in accordance with the timing, prioritization and performance schedule that is included as a part of Exhibit B, at its sole risk, cost, and expense, such additions and/or extensions of the System (including all associated Receipt Points) as are necessary and adequate to receive Producer’s Gas for the services provided for under this Agreement.  **  Exhibit A shows the four (4) segments into which the System project has been divided for purposes of constructing the System in phases.  **  Additionally, Producer may at its option construct, or cause to be constructed at its sole risk, cost and expense, certain additional facilities that are useful for the delivery of Producer’s Gas into the System at certain Receipt Points.  Producer and Gatherer agree that Gatherer shall construct and complete the System in segments and that Producer may at its option expand, operate and maintain Producer’s System for the gathering, compression and treatment of Producer’s Gas prior to the completion of the System by Gatherer.

4.2           When Gatherer has (i) completed a segment of the System (“Completed Segment”), and (ii) connected the Completed Segment to Producer’s System, with the result that Gatherer can gather, compress, dehydrate and, if required, Treat Producer’s Gas delivered into such Completed Segment, then Gatherer shall immediately acquire and assume the operation, maintenance and control of the applicable portion of Producer’s System that Gatherer has connected to the Completed Segment, and such portion of Producer’s System shall thereafter be included in the definition of Completed Segment and all of the terms of this Agreement shall be applicable for such Completed Segment.  For all Wells connected at the time of acquisition to the section of Producer’s System being acquired pursuant to the foregoing

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provisions, the Receipt Points for such Wells shall be considered to be located in accordance with the provisions of Section 1.24, above, which define “Receipt Points.”

4.3           The parties expressly agree that the categories of assets, rights and interests referred to on Exhibit B-1 to this Agreement, whether now owned by Producer or hereafter acquired by Producer after the execution of this Agreement, are excluded from the meaning of the term “Producer’s System,” and Gatherer shall have no right under this Agreement, under any circumstances, to acquire any portion of those assets, rights and interests.  The parties expressly understand and agree that, notwithstanding any other provision of this Agreement that may appear to be to the contrary in any respect, any rights Gatherer has under this Agreement to acquire all or portions of Producer’s System are expressly limited to facilities and assets of Producer that are physically connected to the System between the Receipt Points and the Delivery Points.  Gatherer shall have no right to acquire any facilities or other assets of Producer located upstream of the Receipt Points.

4.4           The sale by Producer and the acquisition by Gatherer of all or any part of Producer’s System under this Article IV shall occur on an “as-is, where-is” basis with no express or implied representations or warranties provided by Producer to Gatherer, except that Producer agrees to transfer Producer’s System, or applicable portions thereof, free and clear of any mortgages, mechanics’ liens, tax liens and other forms of security interests or financial encumbrances or past due payments of any kind created by, through and under Producer but not otherwise (and Gatherer shall not pay Producer any purchase price until being reasonably assured that there are no such encumbrances), and shall be deemed to represent and warrant to Gatherer that Producer has good and clear title to the personal property associated with the acquired portion of Producer’s System.  The acquisition shall be consummated by special warranty assignment or transfer of necessary or relevant equipment leases or other facility leases, permits, rights of way, easements, surface use leases and real property interests, to the extent that both (a) such items are assignable by Producer to Gatherer without unreasonable expense, and with a representation that to the best of Producer’s knowledge, such leases, permits, rights of way and easements are valid and in full force and effect, and Producer’s operations are in material compliance with the same and (b) Producer does not need to retain such items for the continued operations or business activities of Producer.  Producer will make reasonable efforts to obtain all governmental and third party consents and approvals necessary to complete the transactions contemplated by this Section.  If Producer is unable to obtain any required consents, or the interests are not assignable or transferable, or if Producer determines that such items are required by Producer for the continued operations or business activities of Producer, Producer shall, to the extent Producer may lawfully and validly do so, “partially” grant to Gatherer a non-exclusive right and license to use any such equipment leases and other facility leases, permits, easements, surface use leases, rights of way and/or real property interests associated with the acquired portion of Producer’s System, the intent of the Parties being to provide Gatherer, to the extent the same can be reasonably done, with the same access and ability to utilize such items as if Producer had assigned such items to Gatherer. Producer shall further sign and deliver to Gatherer a bill of sale conveying the equipment and personal property that comprise the acquired portion of Producer’s System.  The acquisition price for the acquired segment of Producer’s System shall be **.  The Parties shall have a period of 180 days after the acquisition of any portion of Producer’s System within which to conduct post-closing accountings, in order to account for any remaining sums to be paid by Gatherer to Producer as a result of such acquisition.

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4.5           Producer shall bring all facility leases or other related contracts that are acquired in whole or in part by Gatherer from Producer current in all payments and obligations due and owing as of the date of assignment, and Gatherer shall assume sole liability for all ongoing payments and obligations due and owing after the date of Producer’s assignment and shall indemnify and hold Producer harmless with respect to any future payments and obligations under such assigned facility leases or other related contracts with respect to the period after the date of transfer to Gatherer.  Producer shall not be required to assign easements, rights-of-way, leases or other related contracts to Gatherer, either whole or in part, if doing so would incur liabilities unless Gatherer bears all costs and burdens associated with such liabilities. Producer shall indemnify and hold Gatherer harmless from and against any payments, liabilities and obligations arising or accruing under such assigned facility leases or other related contracts with respect to the period prior to the date of transfer to Gatherer, or any obligations, liabilities, duties or damages related to the operations of Producer’s System, prior to the date of transfer to Gatherer, including any environmental liabilities.  Gatherer shall indemnify and hold Producer harmless from and against any payments, liabilities and obligations arising or accruing under such assigned facility leases or other related contracts with respect to the period after the date of transfer by Producer, or any obligations, liabilities, duties or damages related to the operations of Producer’s System, after the date of transfer to Gatherer, including any environmental liabilities.

4.6           The Parties agree that Producer has entered into, or intends to enter into,  contracts with certain manufacturers of compression packages, as listed in Exhibit F, (“Compressor Contract”), under which Producer shall be obligated to receive and lease certain compression packages. The Parties also agree and understand that when Gatherer purchases segments of Producer’s System as set forth in this Agreement, that Producer may have received and installed one or more of the subject compression packages associated with such Compressor Contract. At the time that Gatherer purchases a segment of Producer’s system, Producer will assign, and Gatherer will assume, the duties of the lessee under the leases and any other obligations associated with such compression packages that are associated with the segment of Producer’s System.  At the time that Gatherer purchases the final segment of Producer’s System, Producer shall assign to Gatherer and Gatherer shall assume the Compressor Contract and the rights and obligations associated with the Compressor Contract.  All compressors then being used and/or remaining to be delivered under the terms of the Compressor Contract assigned by Producer to Gatherer shall be used as part of the System to fulfill Gatherer’s obligations under this Agreement.

4.7           Immediately following the receipt of Producer’s Gas at the Receipt Points associated with the Completed Segment (and, if applicable, after the acquisition of the associated portion of Producer’s System by Gatherer), all of the terms of this Agreement shall apply to the Completed Segment, except that, in order for Gatherer to evaluate the new System hydraulics and modify such hydraulics as necessary, and in acknowledgement that Producer’s System may exceed the Receipt Point pressure requirements under this Agreement, each Receipt Point which was part of Producer’s System prior to connection to Gatherer’s System, shall be allowed a period of one hundred twenty

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(120) days after such connection, before it shall be subject to the Receipt Point pressure requirements of this Agreement, provided, however, that the Receipt Point pressures shall not, even during such one hundred twenty (120) day period, exceed the MAP that existed with respect to that Receipt Point during the Month prior to connection to Gatherer’s System.

Article V.
RECEIPT AND DELIVERY OF GAS

5.1           All of Producer’s Gas delivered under this Agreement shall be delivered to Gatherer at the Receipt Points and redelivered to Producer (or on behalf of Producer) at the Delivery Points as closely as is practicable to uniform hourly and daily rates of flow.

5.2           Producer shall deliver Producer’s Gas to Gatherer at the Receipt Points at a pressure sufficient to effect delivery into Gatherer’s System, against the pressure prevailing therein from time to time; provided, however, that subject to those items set forth in Section 7.8 referencing this Agreement’s provisions allowing higher Receipt Point pressures for a temporary period, Producer shall not be required to deliver Producer’s Gas at a pressure greater than **.  Producer shall be responsible for making timely arrangements for the further disposition of Producer’s Gas at and from the Delivery Points.

5.3           The Heating Content of the gas measured at the Receipt Points shall be determined on a water-saturated MMBTU basis at Standard Base Conditions.

5.4           Gatherer shall redeliver on behalf of Producer, to the Pipeline Carrier(s) designated by Producer at the Delivery Point(s), a thermally equivalent quantity of Producer’s Gas equal to the quantity received from Producer at the Receipt Points, less the Deemed Fuel, Deemed System Loss, and Measured Treating Fuel and Loss, and if Producer’s Gas is processed prior to delivery, less the actual fuel and shrinkage resulting from the Processing of Producer’s Gas.   Gatherer shall redeliver Producer’s Gas at each Delivery Point on a dry MMBTU basis at Standard Base Conditions.

5.5           Producer’s Gas shall be given a higher priority by Gatherer than any other Gas delivered into the System.  As such, and subject to applicable laws and regulations, Gatherer shall gather Gas owned by persons other than Producer only to the extent that excess gathering and compression capacity exists within the System.  Gatherer further agrees that, except to the extent it can do so without adversely affecting the Fees and costs to be borne by Producer and/or the ability of Gatherer to receive and/or deliver Producer’s Gas, it will not accept from any third parties Gas that does not meet the quality specifications of the Pipeline Carriers to which Producer’s Gas is to be redelivered by Gatherer, it being the intention that Gatherer retain to the maximum extent as is reasonable, its ability to blend with other conforming Gas in its lines any of Producer’s Gas that does not meet the quality specifications of the Pipeline Carriers to which Producer’s Gas is redelivered.

5.6           Gatherer shall, on no less frequently than a monthly basis, measure the quantity and Heating Value of Producer’s Gas received at each Receipt Point and shall redeliver a thermally equivalent quantity of Gas, less the Deemed Fuel, Deemed System Loss and Measured Treating Fuel and Loss as set forth in Article X and Exhibit G.  If Producer’s Gas is processed prior to delivery, an adjustment shall be made based on the Processing arrangements such that any additional actual volume and heating value (MMBTU) reductions

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that result from such Processing shall further reduce the MMBTUs that Gatherer is obligated to redeliver for Producer’s account at the Delivery Points.

5.7           Producer shall provide estimates to Gatherer as to the expected maximum flow and timing of such flow at each Receipt Point to assist Gatherer in selecting the proper pipeline size required for the connection of the Receipt Point; provided, however, that each set of such information provided by Producer is only an estimate, and Producer shall have no liability to Gatherer for any differences between the estimates provided by Producer in good faith, and the actual maximum flow and timing of such flow at the Receipt Points.

5.8           Gatherer shall construct such pipelines, measurement equipment and other facilities as may be reasonably needed in order for Gatherer to promptly receive all of Producer’s Gas from Well(s) within the Commitment Area at the Receipt Points after such Wells have been completed and are ready to flow Gas to a Completed Segment.    With respect to any Completed Segment of the System, Producer shall provide Gatherer with prior written notice, as set forth in Exhibit D, advising Gatherer of the location of the Well and the location of the Receipt Point designated by Producer (a “Well Notice”).]  It is expressly understood and agreed that all risks and expenses associated with all aspects of the timely construction of the pipelines and other facilities, including but not limited to the procurement of the rights-of-way needed or useful in connection therewith, shall be the sole risk and expense of Gatherer.

5.9           If Gatherer has not completed the installation of the pipelines and other facilities required or useful in order for Gatherer to be prepared to fulfill its obligations under this Agreement with regard to Producer’s Gas from any Well or central production facility within the period of time set forth in Exhibit D, Producer shall have the option to do any of the following:

5.9.1        Install, or cause to be installed, such pipelines and/or other facilities.  Upon the completion of such pipeline and/or other facilities, Gatherer shall be obligated to immediately commence receiving into its System Producer’s Gas delivered by Producer through the newly-constructed facilities.  Additionally, Gatherer shall be obligated to promptly acquire such pipeline and/or other facilities from Producer ** Costs incurred by Producer in connection with the installation of such pipeline and/or other facilities.  Payment shall be due from Gatherer as to each invoice within thirty (30) days of Gatherer’s receipt of such invoice from Producer.  In order to invoke this option, Producer shall send to Gatherer one or more invoices (i.e., Producer may invoice Gatherer multiple times, as the costs are being incurred) showing Actual Costs incurred by Producer in connection with such pipelines and/or other facilities, with copies of supporting materials showing that the costs have actually been incurred, **.  In the event Producer chooses to install such pipelines and/or other facilities, Producer shall not be obligated to pay Gatherer any Fees for Producer’s Gas delivered to the applicable and related Receipt Point(s) for a period of ** by Gatherer, which time period shall be deemed to commence to run from the date of first delivery of Producer’s Gas into the facilities in question; or

5.9.2        Elect to have such Well or central production facility released from the terms of this Agreement at the sole option of Producer by providing Gatherer with three (3) days written notice of such election, at the end of which period Producer shall be free to enter into any arrangements it may choose for the provision of alternative

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services by any third party of Producer’s choosing, and Producer shall have no further obligations to Gatherer under this Agreement with regard to the Well(s), central production facilities and Receipt Point(s) in question; or

5.9.3        As an alternative to 5.9.1 and 5.9.2, above, Producer may instead elect to take no action and await Gatherer’s delayed performance of the particular obligations that have not been timely performed.  In the event Producer elects this third option, then for every one (1) day of delay in Gatherer’s ultimate completion of the installation of the applicable pipelines and/or other facilities, then Gatherer shall pay to Producer the following compensation per well for Gatherer’s delay in such performance under this Agreement:

(A)  For each day up through the ** of delay beyond the date on which performance was due by Gatherer, Gatherer shall pay to Producer the sum of **

(B)  For each day beginning with ** continuing through the ** beyond the date on which performance was due by Gatherer, Gatherer shall pay to Producer the sum of **

(C)  For each day beginning with ** beyond the date on which performance was due by Gatherer, Gatherer shall pay Producer the sum of **;

provided, however, that Producer may elect at any time that is governed by this Section 5.9.3 to instead proceed reasonably and in good faith under the alternative procedures set forth in either 5.9.1 or 5.9.2, above, subject to the condition that such election not result in an unreasonable or disproportionate incurrence of liability. For example, Producer cannot install only the final 100 feet of pipe under 5.9.3 to avoid paying Gatherer any Fees for Producer’s Gas delivered to the applicable and related Receipt Point for a period of one hundred eighty (180) days following the acquisition of such facilities by Gatherer.

5.9.4        Should Gatherer determine that it will be unable to be fulfill its obligations under this Agreement with regard to Producer’s Gas from any Well or central production facility within the period of time indicated on Exhibit D due to the inability to obtain necessary rights of way, easements, surface use or other real property agreements for consideration of less than 2 times the prevailing market rate, Gatherer shall notify Producer and Producer agrees to meet to discuss in good faith a mutually agreeable remedy to such situation. However, such discussion shall not alter or suspend any of the requirements and provisions under 5.9 through 5.9.3 unless agreed to in writing by the Parties.

5.10         Producer shall have the following additional remedies in the event that Gatherer engages in repetitive (applying the standard set forth in this Section) failures to perform under this Agreement.  The remedies set forth in this Section shall become applicable at such point in time when Producer has drilled, during the term of this Agreement, at least ** are capable of flowing Gas to Gatherer in Completed Segments of the System, and as to which Producer sent Well Notices to Gatherer.  At each subsequent point in time that the cumulative number of new Wells in which Gatherer has failed to have the facilities completed and commence receipt of

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Producer’s Gas on a timely basis in accordance with the times set forth in Section 5.8 and Exhibit D, exceeds ** in the Commitment Area after the date of this Agreement, and as to which Producer sent Well Notices to Gatherer, then Producer may elect, on each such occurrence, to terminate this Agreement in its entirety and acquire the System pursuant to Article XIV.

5.11         Should Producer choose to install pipelines and/or other facilities under Section 5.9.1 in order for Gatherer to fulfill its obligations under this Agreement, Producer shall use substantially the same standards of design as Gatherer has used to construct the System.

5.12         If Gatherer has been provided with a Well Notice, but Producer fails to complete the Well referred to in the Well Notice (or a Well that is the functional substitute for such Well) within ** of the necessary System facilities to be prepared to receive Producer’s Gas from such Well, then Producer shall at the Gatherer’s request, reimburse Gatherer for all of Gatherer’s reasonable and Actual Costs that are directly and solely related to the installation of such facilities, and Gatherer shall at the same time assign and convey to Producer, through appropriate and valid documentation, all of the rights, interests and assets, the cost of which have been reimbursed by Producer.

Article VI.
OPERATIONAL IMBALANCE AND CASH BALANCING

6.1           The parties recognize that following the completion of the System and the purchase by Gatherer of Producer’s system, Gatherer shall be designated by the Pipeline Carriers as the point operator and shall be considered by the Pipeline Carriers to be responsible for the operation of the System’s pipeline interconnections to the Pipeline Carriers. As such, with respect to operational balancing agreements or similar agreements with all Pipeline Carriers (“OBA(s)”) related to the existing pipeline interconnects, Gatherer shall either be appointed and act as agent of Producer, accept assignment of Producer’s agreements, or enter into independent OBA’s. Furthermore, with respect to any subsequent pipeline interconnects to the System as set forth in the Agreement, Gatherer shall likewise either be appointed and act as agent of Producer under its OBA’s or enter into independent OBA’s for such interconnections. Upon entering into all such arrangements for the OBA’s, Gatherer shall be responsible for the administration of all such OBA’s and for all terms and conditions of any such OBA subject to the terms of this Article VI.

6.2           The parties recognize that certain Gas imbalances may occur between the quantity of Producer’s Gas received by Gatherer less Deemed Fuel, Deemed System Loss, and Measured Treating Fuel and Loss (and if the Gas is required to be processed prior to delivery, the volume adjustment provided for in this Agreement) (“Net Receipt”) and the quantity of Producer’s Gas nominated by Producer for delivery by Gatherer to Producer or for Producer’s account at the Delivery Point(s) (“Net Nomination”).  Throughout each Month the parties agree to actively communicate and cooperate with each other, and with any interconnecting pipeline, to review appropriate data to identify any imbalance, and to eliminate or remedy any imbalance as soon as either party becomes aware of an imbalance.  The parties further agree to manage daily receipts and deliveries so that the imbalances shall be kept as near to zero as practicable.  At the end of each Month, any imbalance in MMBTUs between the Net Receipt and the Net Nominations (with such difference being referred to as the “Imbalance”) shall be balanced by

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means of a payment to Producer from Gatherer or a payment to Gatherer from Producer, as applicable, valued at the “Cash-Out Price.”  To the extent that the Monthly Net Receipt amounts are greater than the Monthly Net Nomination amounts, a payment shall be due Producer, and Gatherer will make such payment to Producer for the imbalance based on the difference between the Monthly Net Receipt amounts and the Monthly Net Nomination amounts, multiplied by the Cash-Out Price.  To the extent the Monthly Net Receipt amounts are less than the Monthly Net Nomination amounts, a payment shall be due Gatherer, and Gatherer will invoice Producer for the imbalance based on the difference between the Monthly Net Receipt amounts and the Monthly Net Nomination amounts, multiplied by the Cash-Out Price during the applicable Month in which the volume imbalance was generated.  As used in this Agreement, the “Cash-Out Price” shall be determined as to each applicable Month and shall mean  a price per MMBTU equal to either (1) if the receiving pipeline’s applicable cash-out price is not imposed for the applicable Month(s), the price will be the daily index price averaged for such Month for the applicable receiving pipeline as published in the Daily Price Survey section of Platt’s Gas Daily, or (2) if the receiving pipeline’s applicable cash-out price is imposed is imposed for the applicable Month(s), that price will be the “Cash-Out Price” .  Should the information necessary to calculate the “Cash-Out Price” not exist for the receiving pipeline or cease to be available, Gatherer and Producer shall work in good faith to determine a comparable substitute publication and/or daily posting(s) or other indexes providing equivalent data.

6.3           Producer shall be solely responsible for submitting appropriate nominations to Gatherer for the redelivery of Producer’s Gas, less the applicable fuel and loss, at the Delivery Point and shall be responsible for any and all delivery imbalances occurring with respect to Producer’s Gas which is moving under applicable OBA’s or Producer’s Pipeline Carrier transportation agreement(s) or other agreement(s) to the extent that such imbalances are caused by Producer’s failure to make proper and timely nominations. Producer shall indemnify and hold Gatherer harmless from any and all costs, expense, liabilities, or damages (including without limitation, pipeline imbalances, penalties, court costs, and attorney fees) arising due to any such pipeline imbalances on under applicable OBA’s or Producer’s Pipeline Carrier transportation agreement(s) or other agreement(s) caused by Producer’s failure to make proper and timely nominations, provided such indemnification shall apply without duplication of the Cash-Out payments to Gatherer provided for in Section 6.2 above.  Gatherer shall indemnify and hold Producer harmless from and against any and all costs, expense, liabilities, or damages (including without limitation, pipeline imbalances, penalties, court costs, and attorney fees) arising due to any such pipeline imbalances under applicable OBA’s or Producer’s Pipeline Carrier transportation agreement(s) or other agreement(s) caused by Gatherer’s failure to properly and timely give effect to Producer’s nominations, however, Gatherer shall not be responsible for eliminating any imbalances between Producer and any third party. Furthermore, Gatherer shall not be obligated to materially deviate from its normal operating and accounting procedures to reduce or eliminate any such imbalances.

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Article VII.
RECEIPT PRESSURES AND REMEDIES

7.1           Gatherer agrees to maintain the monthly average pressure (“MAP”) at each Receipt Point at **. The MAP shall be determined individually as to each Receipt Point, and the MAP at each Receipt Point shall be determined by dividing the sum of daily average Receipt Point pressures as continuously measured using EFM’s (as defined in Section 8.1, below) during any Month by the number of days in the subject Month.   Gatherer shall maintain for at least seven (7) years, the records that demonstrate the appropriate MAP for each Receipt Point as to any given month.  Producer shall have the right to have access at all reasonable times to Gatherer’s SCADA system information related to the pressure and flows at each Receipt Point.  It is expressly agreed by Gatherer that Gatherer will not destroy any of the foregoing categories of records without first providing Producer with sixty (60) days prior written notice of both its intention to do so and its offer to send and relinquish such materials to Producer in lieu of destroying them.

7.2           Producer and Gatherer understand that the pressure at each Receipt Point may be affected by the initial production from Wells recently connected to the System. As a result, all the Receipt Points within a single Section of Land in which the  combined volume from all the wells within that Section of Land ** be excluded from the determination of the MAP during the period of time that is the lesser of (A) the period that the combined volume of all wells within that Section of Land are delivering ** and such production is causing the MAP at any Receipt Point in such Section ** (B) ** provided, however, that in no event may the MAP at any Receipt Point within such Section of Land **.

7.3           In the event the MAP at any Receipt Point **, then the following shall apply:

7.3.1        In the event the MAP at any Receipt Point **, then Gatherer shall pay to Producer, within fifteen (15) days from and after the end of the applicable Month, **.

7.3.2        In the event the MAP at any Receipt Point **, then, in lieu of the payments outlined in paragraph 7.3.1 above, Gatherer shall pay to Producer, within fifteen (15) days from and after the end of the applicable Month, **.

7.3.3        In the event the MAP at any Receipt Point exceeds **, in addition to the payments outlined in paragraph 7.3.2 above, Gatherer shall pay to Producer monthly, within fifteen (15) days from and after the end of the applicable Month, for each Well attached to the Receipt Point, **.

By way of illustration of the manner in which the sums under Sections 7.3.1 and 7.3.2 are to be calculated:  **.

7.4           Should the MAP at any specific Receipt Point **, or should the MAP at such Receipt Point **, Producer may at its option (to be exercised at any point in time prior to the Gatherer’s restoration of the MAP **:

7.4.1        Elect to have such Receipt Point released from the terms of this Agreement by providing Gatherer with three (3) days written notice of such election, at the end of which period Producer shall be free to enter into any arrangements it may choose for the provision of alternative services by any third party of Producer’s choosing, and Producer shall have no further obligations to Gatherer under this Agreement with regard to the Receipt Point(s) in question. In the event that Producer elects to invoke the provisions of this Section 7.4.1 with respect to a Receipt Point(s), Producer shall not connect more than 16 wells to each affected Receipt Point.; or

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7.4.2        Producer may elect to receive the same compensation as is provided for in Section 7.3 above except that the dollar amounts applicable to the stated fact situations shall be doubled.

7.5           Should the MAP at any Receipt Point **, Producer may at its option (to be exercised at any point in time prior to the Gatherer’s restoration of the MAP for the Receipt Point to 45 psig), do the following:

7.5.1        Elect either of the options set forth in Sections 7.4.1 and 7.4.2, above; or

7.5.2        Install, or cause to be installed, such facilities as are reasonably needed in order to eliminate the pressure problems.  Upon the completion of such facilities, Gatherer shall be obligated to immediately commence receiving into its System Producer’s Gas delivered by Producer.  Additionally, Gatherer shall be obligated to promptly acquire such facilities from Producer ** incurred by Producer in connection with the installation of such facilities.  Payment shall be due from Gatherer as to each invoice within thirty (30) days of Gatherer’s receipt of such invoice from Producer.  In order to invoke this option, Producer shall send to Gatherer one or more invoices (i.e., Producer may invoice Gatherer multiple times, as the costs are being incurred) showing Actual Costs incurred by Producer in connection with such pipelines and/or other facilities, with copies of supporting materials showing that the costs and expenses have actually been incurred, **.

7.6           Gatherer shall provide to Producer, on or before the 15th day of each Month, a written statement indicating the MAP for each Receipt Point during the preceding Month, together with a statement advising Producer of the percentage of Receipt Points during such Month as to which the MAP **.

7.7           Beginning in June, 2007,  whenever either of the following occur:

(a) more than **

(b) more than **

with such occurrence extending for a period of ** provisions of this Article VII, Gatherer shall provide Producer with written notice of such occurrence no later than **, as applicable, together with a description of Gatherer’s proposed plan and timetable for correcting the excessive System pressure problems.  Producer may thereafter elect to terminate this Agreement **.  The provisions of this Section shall apply each time the above conditions are present.

7.8           Any Receipt Point where the increase in pressure is a result of (i) the delivery of gas in excess of the volume set forth in Section 7.2 above, (ii) the delivery of gas from wells that were connected to Producer’s System prior to the connection to Gatherer’s System for a period of one hundred twenty (120) days following the purchase of any portion of Producer’s System as set forth in Article IV, above, (iii) the operations of any third party providing Processing or additional treating for Producer’s Gas, or (iv) the delivery of free liquids or Inferior

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Liquids by Producer, such Receipt Point shall be excluded from the determination of Receipt Point MAP’s as set forth above.

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Article VIII.
MEASUREMENT

8.1           Gatherer shall measure the Producer’s Gas delivered by Producer hereunder using electronic flow meters (“EFM”), which Gatherer shall install, or caused to be installed, at the Receipt Points and Delivery Points. Measurement shall be made by Gatherer in accordance with the requirements of applicable provisions in ANSI/API 2530, “Orifice Metering of Natural Gas” (American Gas Association Gas Measurement Committee Report No. 3) of the Natural Gas Department of the American Gas Association, as amended from time to time, or by any other method commonly used in the industry and mutually acceptable to the parties.  EFM equipment shall be designed and installed in accordance with the procedures set forth in the Manual of Petroleum Standards, Chapter 21.1 (Latest Revision).  Producer shall have access to Gatherer’s metering equipment and information received from such metering equipment at reasonable hours.  In addition, Producer shall have the right to install check measurement / monitoring equipment at the Receipt Points and Delivery Points - including the right to install Producer’s check measurement equipment on the Gatherer’s meter tube(s) and/or orifice unions.  All such check measurement equipment shall be installed so such equipment shall not interfere with the operations of Gatherer’s equipment.

8.2           The accuracy of Gatherer’s measuring equipment shall be verified by meter calibrations and orifice inspections, and a chromatographic analysis shall be conducted, using means and methods generally acceptable in the gas industry once every six (6) Months for Receipt Points which average less than 500 MSCF per day, every three (3) Months for Receipt Points which average between 501 — 1000 MSCF per day, and every one (1) Month for Receipt Points that average 1001 MSCF per day or more. Measuring equipment found to be measuring and/or reading inaccurately shall be adjusted to measure and read accurately. Gatherer shall give Producer two (2) days notice of upcoming tests. If Producer fails to have a representative present, the results of the test shall nevertheless be considered accurate until the next test. Gatherer shall, upon written request of Producer, conduct a test of Gatherer’s measuring equipment and/or a chromatographic analysis, provided that in no event shall Gatherer be required to test its equipment more frequently than once a Month. All tests of such measuring equipment shall be made at Gatherer’s expense, except that Producer shall bear the expense of any additional tests made at Producer’s request.

8.3           If for any reason, any measuring equipment is inoperative or inaccurate by more than two percent (2%) in the measurement of Gas, then the volume of Producer’s Gas delivered by Producer to Gatherer during the period of such inaccuracy shall be determined on the basis of the best data available using the first of the following methods which is feasible:

(a)By using the registration of any check measuring equipment installed and accurately registering; or

(b)By using a percentage factor to correct the error, if the percentage of error is ascertainable by calibration, test, or mathematical calculations; or

(c)By comparing deliveries made during preceding periods under similar delivery conditions when the meter was registering accurately.

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8.4           Any adjustment based on such determination shall be made for such period of inaccuracy as may be definitely known or, if not known, then for one half (1/2) the period since the date of the last meter test. In no event, however, shall any adjustment based on measurement of quantities, pressure or quality, extend back to transactions beyond six (6)  months  from the date the error was first made known by one party hereunder to the other.

8.5           Each party shall have the right to inspect the other party’s equipment, and other measurement or test data during business hours; but the reading, calibration, and adjustment of such equipment shall be done by the party installing and furnishing same. Unless the parties agree otherwise, each party shall preserve for seven (7) years, all of its original test data, accounting materials and other records pertinent to the actions taken, and the performance delivered, under this Agreement. It is expressly agreed by Gatherer that Gatherer will not destroy any of the foregoing categories of records without first providing Producer with sixty (60) days prior written notice of both its intention to do so and its offer to send and relinquish such materials to Producer in lieu of destroying them.

Article IX.
GAS QUALITY AND SPECIFICATIONS

9.1           Producer shall deliver to Gatherer at the Receipt Points Gas which is commercially free of dust, rust, gum and gum forming constituents, dirt, paraffin, impurities, and other solid or liquid matter which might cause injury to or interference with the proper operation of the lines, meters, regulators and other appliances through which it flows. Subject to the other provisions of this Article IX, Producer’s Gas as delivered to the Receipt Points, shall also conform to the following specifications (the “Specifications”):

(i)	Oxygen	No oxygen
(ii)	Free Water	No free water
(iii)	H2S	No more than one quarter (1/4) grain per one hundred (100) Standard Cubic Feet of Gas
(iv)	Total Sulfur	Including mercaptan and hydrogen sulfide, not to exceed one half (1/2) grain per one hundred (100) Standard Cubic Feet of Gas
(v)	Temperature	No more than one hundred twenty degrees Fahrenheit (120°F) and no less than sixty degrees Fahrenheit (60°F)
(vi)	Carbon Dioxide	**
(vii)	Nitrogen	No more than two percent (2%) by volume
(viii)	Other	Any additional or more stringent specification imposed by the Pipeline Carriers (other than the specification for Carbon Dioxide)

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9.2           If, at any time during the term of this Agreement, either party ascertains that Producer’s Gas fails to meet the Specifications, notwithstanding efforts to blend the Gas as provided for below in Section 9.3 below, such party shall immediately notify the other of the extent of the deviation from the Specifications. Producer shall determine the expected duration of such failure and notify the Gatherer of the efforts Producer is undertaking to remedy such deficiency. In the event Producer cannot (or elects not to) remedy such deficiency, Gatherer may refuse to accept delivery of Producer’s Gas, or accept delivery of Producer’s Gas pursuant to mutually agreed upon increased Fees or other adjustments to revenues by Gatherer to compensate Gatherer for addressing such deficiencies. In such case, Gatherer and Producer shall work in good faith to determine a solution to the Specification deficiencies.

9.3           If Gatherer can blend any of Producer’s Gas that either fails to meet the Specifications set forth in Section 9.1, above, or fails to meet any other required specifications, with other Gas in the System, and such blending will cause the composite Gas composition to meet such Specifications, Gatherer will accept such non-conforming Producer’s Gas, without any additional payment from or detriment to the Producer as long as such blending does not cause undue operational problems or impacts.

9.4           In the event Gatherer cannot accept, after application of Section 9.3, any of Producer’s Gas that fails to meet the Specifications set forth in Section 9.1, above, then Producer, or an affiliate of Producer, Gatherer, or a third party contracted by Producer for such purpose, shall have the right to tie-in to the System at no cost to Gatherer for the purpose of providing such additional Treating as may be required for Producer’s Gas, provided that the additional Treating will not cause or result in a decrease in pressure of the Gas.  The additional Treating of Producer’s Gas by Producer, its affiliates, or any third party, will not include the **.  In the event Producer, or an affiliate of Producer, Gatherer or a third party contracted by Producer installs such additional Treating facilities, Gatherer shall install all required measurement and other equipment on the gas streams entering and exiting the additional Treating facilities, and all associated fuel gas pipelines to accurately measure the actual fuel and loss associated with the additional Treating.  Producer shall reimburse Gatherer for the reasonable and Actual Costs of installing such additional equipment and the actual fuel and loss associated with the additional Treating shall be included in the calculation of the Measured Treating Fuel and Loss.

9.5           If Producer determines that there is a need or a desire to perform any activity with respect to Producer’s Gas for any purpose deemed reasonably necessary by Producer, other than for services already to be provided by Gatherer hereunder and for additional Treating for non-conforming gas, as per Section 9.4, then Producer, an affiliate of Producer, and/or a third party contracted by Producer shall have the right to tie-in to the System to remove Producer’s Gas from and redeliver Producer’s Gas to the System.  Any removal and redelivery pursuant to this Section shall be subject to the requirement that the Gas be delivered back into the System at a pressure not less than that existing prior to its removal from the System.  Gatherer shall install all required measurement and other equipment to measure the quantity of Producer’s Gas removed from and redelivered to the System.  Producer shall reimburse Gather for the reasonable and Actual Costs of installing such additional equipment.  The difference between the quantity of gas removed and the quantity of gas redelivered shall be included in the calculation of the Measured Treating Fuel and Loss. All Treating to remove

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CO2 from Producer’s Gas, other than additional treating as set forth in Section 9.4 above, shall be provided by Gatherer.

9.6           Producer shall reimburse Gatherer the reasonable and Actual Costs to dispose of any water from Producer’s Wells that is inadvertently flowed into the System.  Any such costs shall be invoiced to Producer on a Monthly basis.

Article X.
GATHERING, COMPRESSION, TREATING FEES, LINE LOSS, AND FUEL CHARGE

10.1         For the gathering services provided by Gatherer hereunder, Producer shall pay Gatherer a gathering fee (“Gathering Fee”) for each MSCF of Producer’s Gas delivered to Gatherer by Producer at the Receipt Points equal to the per MSCF rate set forth in Exhibit G.

10.2         For the compression services provided by Gatherer hereunder, Producer shall pay Gatherer a compression fee (“Compression Fee”) equal to the per MSCF rate set forth in Exhibit G.

10.3         Subject to Section 9.3, if the average CO2 content in the Producer’s Gas delivered by Producer at any Treating facility installed or acquired by Gatherer exceeds the CO2 content permitted by the applicable Pipeline Carriers, then Producer shall pay a Treating fee (“Treating Fee”) with respect to that Gas. The Treating Fee shall be the per MSCF rate set forth in Exhibit G.  Because it will be difficult to anticipate how much of Producer’s Gas will be consumed as fuel and loss, how much of Producer’s Gas will need to be treated, and what the CO2 content of Producer’s Gas will be, Gatherer will install all required measurement and other equipment on the gas streams entering and exiting the treating facilities, and all fuel gas pipelines to accurately measure the actual Treating fuel and loss at each Treating plant location (“Measured Treating Fuel and Loss” which term may include fuel and loss associated with Processing or additional treating of Producer’s Gas).

10.4         Producer and Gatherer agree that **.  However, **, and annually thereafter, the Gathering Fee, total applicable Compression Fee and Treating Fee  specified above, shall be subject to being increased on an annual basis, **, in the Consumer Price Index as published by the Department of Labor, in the subsection titled “Not Seasonally Adjusted U.S. City Average All Items” (“CPI”); provided, however, that no such increase in Fees **

10.5         As to time periods prior to **, the parties specifically agree as follows:  If during any month the “Last Three-Day price” for natural gas, as published in the above-referenced section of Platts, exceeds the price set forth on Exhibit H, then Producer agrees to pay Gatherer an additional fee for services provided by Gatherer during such applicable month.  ** that such published “last three-day” average closing prices exceed the natural gas prices set forth in Exhibit H.  This increase in Fees shall not change the base Fees; rather, the increase is an additional payment obligation that may be effective, or not, from month-to-month if and when the circumstances that give rise to such additional payment (as described in the preceding sentence of this paragraph) occur.

10.6         Gatherer shall assess, as set forth in Exhibit G, a charge for deemed compression fuel (“Deemed Fuel”) and for lost and unaccounted for Gas (“Deemed System Loss”).

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10.7         The dehydration services shall be provided without additional compensation from Producer to Gatherer, and fuel utilized in dehydration shall be considered as part of the Deemed Fuel set forth above.

Article XI.
BILLING, PAYMENT, AND REPORTING

11.1         On or before the fifteenth (15th) day of each Month, Gatherer shall render an invoice to Producer for the preceding Month’s services by Gatherer.  Gatherer shall provide Producer with information to support Gatherer’s invoice identified on a “Receipt Point by Receipt Point” basis, and shall also show the cumulative information indicating the total quantity of Producer’s Gas delivered hereunder, the amount due therefore, and information sufficient to explain and support any adjustments made by Gatherer in determining the amount billed. Except where other provisions of this Agreement provide shorter deadlines for the payment of certain sums and/or invoices under the terms of this Agreement, Producer shall pay Gatherer or Gatherer shall pay Producer, as the case may be, at the address shown hereunder within thirty (30) days of receipt of invoice.  If the correct amount is not paid when due, interest on any unpaid and undisputed portion shall accrue at an annual effective interest rate  equal to the prime rate, as quoted by the Wall Street Journal, plus two percent (2%) or at the highest rate permitted by applicable law, whichever is lower, from due date until date paid, with such interest to be compounded monthly.  If Producer does not pay Gatherer all undisputed amounts within the later of (i) ninety (90) days following receipt of invoice or (ii) thirty (30) days following notice from Gatherer that undisputed amounts are due, then Gatherer may suspend receipt of Gas hereunder without prejudice to any other available remedies at law or in equity.  Whenever Producer is entitled to be paid any sums by Gatherer under the terms of this Agreement, then unless specifically provided otherwise with regard to specific situations under the terms of this Agreement, payment shall be due from Gatherer and interest shall be owing under the same time frames and procedures set forth above in this paragraph 11.1 in relation to sums owing by Producer to Gatherer.

11.2         Either party may, at its option, recoup any sums (or portions thereof) owing by the other party by netting out of such party’s payments to the other party all or part of the sums owed by the other Party under this Agreement.  When a party elects to net out certain indebtedness of the other party, such party shall promptly send to the other party a description of (a) the source or nature of the indebtedness of the other party that has been recouped in whole or in part by such party in the above-referenced manner, including the dollar amount of such recoupment, and (b) the indebtedness of the party that has been reduced through such recoupment.

11.3         When Gatherer owes to Producer any additional sums under this Agreement by virtue of Gatherer’s delay in performance, or non-performance, of any of Gatherer’s obligations under this Agreement, Gatherer shall, at the same time as Gatherer sends Producer its invoices for sums owing by Producer as to a given Month, both (a) calculate any such sums that Gatherer owes to Producer for the same month, and (b) reflect a credit thereon or remit such sums to Producer by the due date of the invoice.

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11.4         If any overcharge or undercharge due to clerical or arithmetic error shall at any time be found relative to any invoice or other statement delivered by Gatherer in connection with this Agreement, whether outstanding or paid, Gatherer shall refund any amount of overcharge, or Producer shall pay any amount of undercharge, as the case may be, within thirty (30) days after final determination thereof; provided, however, that all statements that have not been challenged in writing or corrected in writing, within twenty-four (24) Months from the end of the Month in which the statement was received by the party for whom it was intended, shall be conclusively deemed to be correct and accurate, and no retroactive adjustment shall be made beyond such twenty-four (24) Month period with regard to any such statements.

11.5         Both parties hereto shall have the right at any and all reasonable times to examine the books and records of, and to audit, the other party to the extent necessary to verify the accuracy of any statement, charge, computation, or demand made pursuant to this Agreement. Prior to such examination, the party requesting confidential information of the other party shall, if requested by the other party, execute a confidentiality agreement of reasonable form and scope after giving the other party 15 days written notice.

Article XII.
TAXES

12.1         Gatherer shall have no duties or liabilities under this Agreement with regard to the reporting of production taxes imposed with respect to the Producer’s Gas delivered and gathered hereunder, except to the extent that any such reporting obligations are specifically imposed by statutes, rules and regulations and/or other laws on Gatherer.

12.2         Gatherer shall file all reports and pay all ad valorem or other similar taxes, fees, or assessments imposed by any governmental authority with respect to the System and ownership thereof.  Producer shall pay or bear all severance or other similar taxes, fees, or assessments imposed by any governmental authority on Producer’s Gas delivered hereunder, except to the extent that any portion of such taxes is to be borne by other persons or entities under the terms of applicable statutes, rules and regulations and/or other laws.  Further, Producer represents that it has timely filed, or shall in the future timely file, any and all reports which it was, or may be, required to file with respect to production or severance taxes to be paid on Producer’s Gas.  Producer shall indemnify and hold Gatherer harmless with respect to any claims that may be made against Gatherer by virtue of any failure on the part of Producer to file any and all of such reports, or with respect to Producer’s failure to pay or bear any and all taxes which Producer is obligated to pay, under the above provisions of this Section 12.2.  Gatherer likewise shall indemnify and hold Producer harmless with respect to any claims that may be made against Producer by virtue of either (a) any failure on the part of Gatherer to file any and all of the reports provided for above in this Section 12.2, and/or (b) any failure on the part of Gatherer to pay any and all taxes which Gatherer is obligated to pay pursuant to the above provisions of this Section 12.2.

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Article XIII.
CONTROL, POSSESSION, TITLE AND ADDITIONAL INDEMNIFICATION

13.1         Producer shall indemnify and hold Gatherer harmless from liability with respect to Producer’s Gas or Producer’s operations for the delivery of such Gas prior to the Gas being delivered into Gatherer’s System and with respect to the operations of any third party providing Processing or additional treating of Producer’s Gas on Gatherer’s System.  Gatherer shall indemnify and hold Producer harmless from liability with respect to Producer’s Gas delivered into the System and prior to delivery thereof at the Delivery Point, except for any such liability relating to the title to Producer’s Gas, which liability shall remain with Producer.

13.2         Producer warrants that it possesses either title to, or the right to deliver to Gatherer, all of Producer’s Gas delivered or caused to be delivered hereunder.  Producer warrants that Producer’s Gas is free from all liens and adverse claims of every kind and agrees to indemnify Gatherer from all suits, actions, debts, accounts, damages, costs, losses, and expenses arising from or out of adverse claims of any or all persons, including governmental entities, as to title to Producer’s Gas or as to royalties or charges thereof.  Notwithstanding the indemnification of Producer by Gatherer for all of Producer’s Gas delivered into the System after receipt thereof by Gatherer and prior to delivery thereof at the Delivery Point, title to the Producer’s Gas delivered or caused to be delivered by Producer to Gatherer hereunder at the Receipt Points shall remain with Producer and shall not pass to nor vest in Gatherer at any point under this Agreement.

13.3         Gatherer shall be entitled to and shall own all condensate and pipeline drip collected in the System at locations beyond the Receipt Point.

13.4         Producer agrees to defend, indemnify and hold Gatherer, its parent, subsidiary and affiliate companies, their agents, employees, directors, officers, servants, invitees and insurers (together, the “Gatherer Group”), harmless from and against any and all losses, claims, demands, liabilities or causes of action of every kind and character, in favor of any person or party, for loss or damage to property of Producer Group (as defined below) or injury to or illness or death of any employee of Producer Group, which loss, damage, injury, illness or death relates to, arises out of or is incident to the work or services performed by Producer under this Agreement, and regardless of the cause of such loss, damage, injury, illness or death, except to the extent that any such losses, claims, demands, liabilities or damages, are the result of the negligence or willful misconduct of Gatherer, or its officers, employees, contractor, agents or representatives. Producer shall fully defend any such claim, demand or suit at its sole expense, even if the same is groundless.  This indemnity shall be limited to the extent necessary for compliance with applicable State and Federal laws.

13.5         Gatherer agrees to defend, indemnify and hold Producer, its joint interest owners, and their respective parent, subsidiary and affiliate companies, and the agents, employees, directors, officers, servants, invitees and insurers of each such entity (together, the “Producer Group”), harmless from and against any and all losses, claims, demands, liabilities or causes of action of every kind and character, in favor of any person or party, for loss or damage to property of Gatherer Group or injury to or illness or death of any employee of Gatherer Group or any employee of subcontractors of Gatherer, which loss, damage, injury, illness or death relates to, arises out of or is incident to the work or services performed by Gatherer under this Agreement, and regardless of the cause of such damage, injury, illness or death, except to the extent that any such losses, claims, demands, liabilities or damages, are the result of the negligence or willful misconduct of Producer, or its officers, employees, contractor, agents or representatives. Gatherer shall fully defend any such claim demand or suit at its sole

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expense, even if the same is groundless.  This indemnity shall be limited to the extent necessary for compliance with applicable State and Federal laws.

Article XIV
ACQUISITIONS

**

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Article XV
REPRESENTATIONS AND WARRANTIES

15.1         Gatherer represents and warrants that:

15.1.1      Gatherer is a limited liability company validly existing and in good standing under the laws of the State of Oklahoma, with the requisite power and authority to own its properties and assets and to carry on its business as now being conducted.

15.1.2      Gatherer has the power and requisite authority to execute and deliver this Agreement and to consummate and perform the transactions contemplated hereby.  The execution and delivery of this Agreement by Gatherer and the consummation and performance of the transactions contemplated hereby have been duly authorized by all necessary action on the part of Gatherer.  This Agreement constitutes the valid and binding obligation of Gatherer, enforceable against it in accordance with the terms hereof, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar laws in effect from time to time, and no other act, approval or proceeding on the part of Gatherer or any other party is required to authorize the execution and delivery of this Agreement by Gatherer or the consummation of the transactions contemplated hereby.

15.1.3      Gatherer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Producer shall have any responsibility whatsoever.

15.1.4      Except as set forth on Exhibit C attached hereto, to the best of Gatherer’s knowledge and belief, there are no actions, suits or proceedings pending against Gatherer which might materially delay, prevent or hinder the consummation of the transactions contemplated hereby.

15.1.5      To the best of Gatherer’s knowledge and belief, there is no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or threatened against Gatherer.

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15.2Producer represents and warrants that:

15.2.1      Producer is a  corporation validly existing and in good standing under the laws of the State of Delaware, with the requisite power and authority to own its properties and assets and to carry on its business as now being conducted.

15.2.2      Producer has the power and requisite authority to execute and deliver this Agreement and to consummate and perform the transactions contemplated hereby.  The execution and delivery of this Agreement by Producer and the consummation and performance of the transactions contemplated hereby have been duly authorized by all necessary action on the part of Producer.  This Agreement constitutes the valid and binding obligation of Producer, enforceable against it in accordance with the terms hereof, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar laws in effect from time to time, and no other act, approval or proceeding on the part of Producer or any other party is required to authorize the execution and delivery of this Agreement by Producer or the consummation of the transactions contemplated hereby.

15.2.3      Producer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Producer shall have any responsibility whatsoever.

15.2.4      Except as set forth on Exhibit C attached hereto, to the best of Producer’s knowledge and belief, there are no actions, suits or proceedings pending against Producer which might materially delay, prevent or hinder the consummation of the transactions contemplated hereby.

15.2.5      To the best of Producer’s knowledge and belief, there is no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or threatened against Producer.

Article XVI.
FORCE MAJEURE

16.1         If either party is rendered unable, wholly or in part by Force Majeure, to carry out its obligations under this Agreement, then the obligations of the affected party, except for any payments due in accordance with this Agreement, so far as the performance of such obligations is prevented or delayed by such Force Majeure, shall be suspended during the continuance of any inability so caused, but for no longer period. Such cause as well as its impacts shall, to the extent possible, be remedied and/or mitigated with all reasonable dispatch. The affected party shall give notice and full particulars of such Force Majeure in writing by mail or telecopy or other electronic facility to the other party as soon as practicable after the occurrence of the cause relied on.

16.2         The term Force Majeure as employed herein shall mean acts of God; strikes, lockouts, or other industrial disturbances; acts of the public enemy, wars, sabotage, blockades, military action, earthquakes, fires, storms or storm warnings, floods; arrests and restraints of governments and people; civil disturbances; explosions; the physical damage of essential parts

29

of Gatherer’s System, which materially interferes with the performance of Gatherer’s obligations hereunder, and which is caused by the acts of third parties who, with respect to the incident causing such damage, have no relation as an officer, director, employee, agent, affiliated entity, contractor, subcontractor or the like, with Gatherer; the inability of any party hereto to obtain necessary materials, supplies, or permits, only where such inability is due to, existing or future rules, regulations, orders, laws, or proclamations of governmental authorities (Federal State or local) including both civil and military; or changes in environmental laws, or the application thereof, which prevent Gatherer from complying with it’s duties hereunder.

16.3         It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party having the difficulty, and that the above requirement that any Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of the opposing party when such course is inadvisable in the discretion of the party having the difficulty.

16.4         Should an event of Force Majeure render Gatherer unable to take delivery of any of Producer’s Gas at any Receipt Point for a period exceeding five (5) consecutive calendar days, then Producer may, upon not less than three (3) days prior written notice to Gatherer, temporarily deliver Producer’s Gas from such Receipt Point to a third party for gathering and/or Processing; provided, however, that Producer’s Gas shall be delivered to Gatherer upon the earlier of the end of the temporary sale or on the first Day of the Month following the Month that the Force Majeure event is rectified to allow delivery to Gatherer.

16.5         Should an event of Force Majeure render Gatherer unable to take delivery of any of Producer’s Gas at any Receipt Points for a period exceeding thirty (30) consecutive calendar days, then unless Gatherer reimburses Producer, within 5 days of receipt of an invoice from Producer, for all out of pocket third party costs incurred by Producer to acquire and construct the required facilities to move Producer’s Gas to an alternate market during the Force Majeure event, Producer may, upon not less than three (3) days prior written notice to Gatherer, permanently deliver Producer’s Gas from those Receipt Points impacted by the Force Majeure event  to an alternate party for gathering, compression and Treating, and will be released from further obligation with respect to those impacted Receipt Points under this Agreement.

Article XVII.
TERM

17.1         This Agreement shall continue in full force and effect for a period of 15 years from the Effective Date (“Primary Term”).  If Producer does not provide Gatherer with written notice, at least ninety (90) days prior to the end of the Primary Term, advising of Producer’s election to terminate this Agreement, this Agreement shall be deemed to be renewed for ** from and after the end of the Primary Term.  **.

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Article XVIII.
ASSIGNMENTS AND SALE OF GATHERER’S SYSTEM

18.1         This Agreement shall extend to and be binding upon the parties hereto, their successors, and assigns. Subject to the provisions of paragraph 18.2, this Agreement and the rights, duties or obligations of the parties hereunder may be assigned or conveyed in whole; provided, however, neither party shall assign or transfer this Agreement and any rights, duties or obligations hereunder, without the prior written consent of the other party, which consent shall not be unreasonably withheld.  A reasonable basis for withholding consent may include the financial condition of the assignee raising reasonable concern relating to its ability to perform under this Agreement.  All assignments and conveyances of either all the wells and leaseholds that are ultimately covered by this Agreement or the System shall be subject to this Agreement and shall not relieve the assignor of its duties hereunder.  No transfer of, or succession to, the interest of any party hereto, either in whole or partially, shall affect or bind the other party until the first Day of the Month following the Month in which the other party shall have received written notification thereof. The acquisition provisions of Article XIV shall not transfer to an assignee or transferee of this Agreement except to the extent provided in Article XIV.

18.2         If Gatherer determines to sell Gatherer’s System to a party other than an affiliate of Gatherer, Gatherer and Producer shall first meet to negotiate in good faith in an effort to arrive at a definitive purchase and sale agreement. If Gatherer and Producer are not able to agree on a definitive purchase and sale agreement after negotiating in good faith for at least sixty (60) days, Gatherer shall have the right to seek offers from other third parties in accordance with the following procedures:

**

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**

18.2.8       If only a portion of the System is addressed in the Third-Party Offer, this right of first refusal shall continue to be applicable to and continue in effect for those portions or elements not part of the Third-Party Offer.

18.2.9       Gatherer will notify all third parties that any proposal, bid or offer for the purchase and sale of any part of Gatherer’s System is subject to Producer’s right of first refusal and will inform such third parties of any applicable requirements of this Agreement related to the purchase and sale of the System.

18.2.10     In no event will the right of first refusal granted to Producer above entitle Producer to match any terms of a sale of all or a portion of Gatherer’s System to an affiliate of Gatherer; rather, the right of first refusal shall apply only to Third Party Offers.

Article XIX.
NOTICES

19.1         Except as herein otherwise provided, any notice, request, demand, payment, invoice, statement, or bill provided for in this Agreement or any notice which either party may desire to give to the other shall be in writing and shall be sent by United States Mail (by regular mail, express mail, certified mail, registered mail or any other available form of United States Mail delivery or other express delivery service that delivers with a speed the same or more rapid than United States Mail, at the election of the sending party) to the below-indicated address of the party intended to receive the same, as the case may be, or to such other address as either party shall designate by future written notice to the other party.  Notice shall be considered to have been given as of the date it is received at the applicable and approved address for the recipient thereof.

If to PRODUCER:

For Notices and Requests:

NEWFIELD EXPLORATION MID-CONTINENT INC.

110 West 7th, Suite 1300

Tulsa, Oklahoma 74119

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Attn:  Operations Manager

Statements, Bills, or Invoices:

NEWFIELD EXPLORATION MID-CONTINENT INC.

110 West 7th, Suite 1300

Tulsa, Oklahoma 74119

Attn: Accounts Payable

Wire Transfer Payments:

**

If to GATHERER:

For Notices and Requests:

MARKWEST WESTERN OKLAHOMA GAS COMPANY, L.L.C.

2500 City West, Ste. 740

Houston, Texas 77042

Attn: Operations Manager

With a copy to:

MARKWEST ENERGY PARTNERS, L.P.

1515 Arapahoe Street, Suite 700

Denver, CO  80202

Attn: Sr. Vice President of Southwest Business Unit

For Statements, Bills, or Invoices

MARKWEST WESTERN OKLAHOMA GAS COMPANY, L.L.C.

6655 S. Lewis, Ste. 350

Tulsa OK 74136

Attn: Accounts Payable

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For Payments

Wire:

**

Article XX.
GUARANTY BY GATHERER’S PARENT ENTITY

20.1         MarkWest Energy Partners, L.P., (“MEPLP”) the parent entity of Gatherer  hereby guarantees to Producer, absolutely, unconditionally and irrevocably, the prompt performance and payment of all the liabilities, obligations and indebtedness owing by Gatherer under this Agreement, and MEPLP is executing and delivering to Producer simultaneously with this Agreement a Guaranty Agreement in the form attached hereto as Exhibit I.

Article XXI.
MISCELLANEOUS

21.1         The interpretation and performance of this Agreement shall be governed by and construed in accordance with the laws of the State of Oklahoma.

21.2         This Agreement contains the entire understanding of the parties superseding all other agreements, whether oral or written, express or implied, except that the confidentiality agreement dated April 7, 2006, previously entered into by the Parties shall not be superseded, but rather shall remain in force and effect.  As a result of the Parties entering into this Agreement, all prior agreements between the Parties hereto that relate to the subject matter of this Agreement have (except as qualified in the preceding sentence) been terminated and replaced by this Agreement.  This Agreement may not be changed orally, but only by an agreement in writing signed by the Party against whom enforcement of any waiver, change, modification, extension, or discharge is sought.  Every covenant, term, and provision of the Agreement shall be construed simply according to its fair meaning and not strictly for or against any Party.  Any waiver of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any subsequent breach by Producer or Gatherer.

21. 3        Gatherer and Producer intend for this Agreement to be enforceable and valid to the fullest extent permitted by applicable law.  If any part or any provision of this Agreement is invalid or unenforceable under applicable law, the invalidity or the unenforceability of that part or that provision shall not affect the validity or the unenforceability of the other parts or the other provisions of this Agreement, and the part or the provision that would otherwise be invalid or unenforceable shall be deemed amended to apply to the broadest extent that it would be enforceable and valid under applicable law.

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21.4         Producer, to the extent it may legally and validly do so (and with no representation or warranty  being made by Producer that it has such ability), hereby quitclaims to Gatherer the non-exclusive and concurrent right to use (including the right to ingress and egress) Producer’s leaseholds, properties, and premises underlying the System in order to carry out the provisions of this Agreement with the right to remove same before or after the expiration of this Agreement and the right to free access at all reasonable times to any part of said leaseholds, properties, and premises.

21.5         The circumstances of this Agreement are such that Producer will be exposed to substantial injury if Gatherer does not timely perform under this Agreement, and the injuries that may occur to Producer could take a variety of forms. Where this Agreement imposes on Gatherer an obligation to pay Producer certain monetary sums, or provide other value to Producer, as a result of certain non-performance or delayed performance under this Agreement, such sums or other value are intended to serve as liquidated damages for certain of the injuries to Producer.  The parties stipulate and agree that (a) the injury that would be caused to Producer as a result of Gatherer’s non-performance or delayed performance would be difficult to estimate accurately, (b) the sums or other value to be provided to Producer under this Agreement in such circumstances are intended to serve as a liquidated damages and not as a penalty, and (c) such sums or other value represent the parties’ reasonable estimate at this time of the probable loss that would be suffered by Producer in the various scenarios addressed in this Agreement.

21.6         The application or the consent by either Gatherer or Producer for or to the appointment of a receiver, a trustee, a custodian or a liquidator for such party or any assets of such party, the admission by Gatherer or Producer of the inability of such party to pay the debts of such entity as such debts become due, the making by Gatherer or Producer of a general assignment for the benefit of creditors, the commencement by Gatherer or Producer of any proceeding relating to bankruptcy, reorganization, liquidation, receivership, conservatorship, insolvency or readjustment of debt or the sufferance by Gatherer or Producer of any such appointment or commencement of any such proceeding not terminated or discharged within     days shall be an event of default under, and a material breach of, this Agreement.

Gatherer and Producer acknowledge and agree that, in any bankruptcy case commenced against or by Gatherer or Producer as debtor, (a) the debtor shall not contest or in any way take any action to oppose the lifting of the automatic stay under Section 362 of the United States Bankruptcy Code to permit the other party to enforce its rights hereunder; (b) the debtor waives all rights that it may have under Section 362 of the United States Bankruptcy Code; (c) the debtor consents to entry of an ex parte order lifting the automatic stay pursuant to Section 362(f) of the United States Bankruptcy Code; and (d) the debtor shall execute, at the option of the other party and upon 48 hours’ written notice, an agreed order lifting the automatic stay.

In addition, in any bankruptcy case commenced against or by Gatherer or Producer as debtor, the debtor shall, at the option of the other party and upon 48 hours’ prior written notice, file a motion to assume this Agreement pursuant to Section 365 of the United States Bankruptcy Code and shall diligently prosecute such motion, using its best efforts to obtain the approval by the relevant bankruptcy court of such motion as soon as practicable.

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21.7         Any dispute, claim or controversy arising out of or relating to this Agreement, or any of the transactions contemplated hereby or thereby, or the breach, termination, enforcement, interpretation or validity thereof, including the determination of the scope or applicability of this Section of the Agreement, shall be adjudicated in, at the election of the party filing the action, either the state district courts or the federal district court in Houston, Texas.  Each party hereby irrevocably submits to the exclusive jurisdiction of the state district courts of Harris County, Texas, located in the City of Houston, for purposes of any litigation that may be brought concerning the subject matters referred to above in this Section; provided, however, that such consent to jurisdiction is solely for the purpose referred to in this Section and shall not be deemed to be a general submission to the jurisdiction of said courts or in the State of Texas other than for such purpose.  Each party hereby irrevocably waives, to the fullest extent permitted by law, any objection that it may now or hereafter have to the laying of the venue of any such proceeding brought in such a court and any claim that any such proceeding brought in such a court has been brought in an inconvenient forum.

21.8         During any time that Producer has delivered an average of greater than 200,000 MSCF per day of gas to Gatherer during the immediately prior three (3) month period, then, subject to applicable laws and regulations, Gatherer agrees not to enter into a contract with a third party for similar services and similar terms and conditions as provided under this Agreement, at Fees and rates that are less than those Fees and rates in effect at such time under this Agreement. In addition, subject to applicable laws and regulations, in no event shall Gatherer enter into a contract with a third party prior to January 2009 for similar services and similar terms and conditions as provided under this Agreement, at Fees and rates that are less than those Fees and rates in effect at such time under this Agreement.

21.9         The captions, titles or headings in this Agreement are for the convenience of the parties in identification of the provisions hereof and shall not constitute a part of this Agreement nor be considered in the interpretation of this Agreement, and the following shall apply:  This Agreement was prepared jointly by the parties hereto and not by any party to the exclusion of the other.

21.10       The failure either Party to exercise any right or rights hereunder shall not be considered a waiver of such right or rights in the future.

21.11       Except for the right of each Party to, at its option, record a recording memorandum of this Agreement in the real property records of the offices of the County Clerks for the applicable Counties where Producer’s Gas leasehold interests or Wells within the Commitment Area and any parts of the System are located in order to impart constructive notice of the existence of this Agreement to third parties, each Party agrees that it shall maintain this Agreement and the contents thereof in strict confidence, and that it shall not cause or permit disclosure thereof to any third party without the express written consent of the other party; provided, however, that disclosure is permitted in the event and to the extent such party is required by a court or agency exercising jurisdiction over the subject matter thereof, by order or by regulation.

21.12       This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same agreement.

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21.13       The terms and provisions of this Agreement are intended solely for the benefit of each party hereto and their respective successors or permitted assigns, and it is not the intention of the parties to confer third-party beneficiary rights upon any other person or entity other than any person or entity entitled to indemnity under this Agreement.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed in several counterparts, each of which is an original, as of the date first written above.

PRODUCER:

	NEWFIELD EXPLORATION MID-CONTINENT INC.
By:	/s/ Lee Boothby
Title:	President

GATHERER:

	MARKWEST WESTERN OKLAHOMA GAS COMPANY, L.L.C.
By:	/s/ Frank Semple
	Frank Semple
Title:	President and CEO

GUARANTOR:

The undersigned hereby joins in this Agreeement to further evidence its guaranty commitments under Section XX, above, and under the Guaranty Agreement referenced therein.

	MARKWEST ENERGY PARTNERS L.P.
By:	/s/ Frank Semple
Title:	President and CEO

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ATTACHMENTS:

Exhibit A:	Map showing geographical scope of the Commitment Area
Exhibit B:	System Schematic, Priorities and Construction Schedule for Construction of Pipeline and Other Facilities
Exhibit B-1:	Categories of Assets, Rights and Interests Excluded from the term Producer’s System
Exhibit C:	Exhibit of Certain Actions, Suits or Proceedings of Producer and Gatherer
Exhibit D:	List of Certain of the Reporting and Notification Obligations
Exhibit E:	NFX System Commitments
Exhibit F:	NFX Compressor Agreements
Exhibit G:	Fee Schedule
Exhibit H:	Limits referred to in Section 10.4
Exhibit I:	Guaranty Agreement (from parent company)

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Exhibit “A”

**

39

GAS GATHERING AGREEMENT

Exhibit “B”

**

40

EXHIBIT “B-I”

**

41

EXHIBIT “C”

MarkWest Eastern Oklahoma Gas Company, LLC Lawsuits

None

Newfield Exploration Mid-Continent, Inc. Lawsuits

None

42

EXHIBIT “D”

**

43

44

EXHIBIT “E”

**

45

EXHIBIT F

**

46

EXHIBIT G

**

47

EXHIBIT H

**

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EXHIBIT I

GUARANTY

THIS GUARANTY dated as of September 21, 2006, is made by MarkWest Energy Partners, L.P., a Delaware limited partnership whose address is 1515 Arapahoe Sheet, Suite 700 Denver, Colorado 80202 (“Guarantor”), in favor of Newfield Exploration Mid-Continent Lnc., a Delaware corporation (“Newfield”), whose address is 110 West 7th Street, Suite 1300 Tulsa, Oklahoma 74119.

WITNESSETH:

WHEREAS, Guarantor owns directly, or indirectly through one or more subsidiaries, all of the outstanding shares of stock in MarkWest Western Oklahoma Gas Company, L.L.C, an Oklahoma limited liability company whose address is 2500 City West, Ste. 740 Houston, Texas 77042 (the “Company”); and

WHEREAS, the Company has entered into one or more agreements with Newfield described on Schedule I hereto (such agreements described on Schedule I, as they may be &om time to time amended, including all other mutual agreements entered into in substitution, renewal or extension therefore or thereof, in whole or in part, being herein collectively called the “Agreements”);

WHEREAS, it is a condition precedent to Newfield’s execution of transactions with the Company pursuant to the Agreements that Guarantor execute and deliver to Newiield a satisfactory guaranty of the Company’s obligations under the Agreements;

WHEREAS, Guarantor and the Company are mutually dependent on each other in the conduct of their respective businesses as an integrated operation; and

WHEREAS, Guarantor’s general partner or general partners have determined that Guarantor’s execution, delivery and performance of this Guaranty may reasonably be expected to benefit Guarantor, directly or indirectly, and are in the best interest of Guarantor;

NOW, TIIEREFORE, in consideration of the premises and of the benefits to be received by Guarantor by virtue of Newfield’s entering into the Agreements, and in consideration of the payment to Guarantor of Ten Dollars and other good and valuable consideration, the receipt and sufficiency of which consideration is hereby acknowledged, and in order to induce Newfield to enter into the Agreements, Guarantor hereby agrees with Newfield as follows:

Section 1.              Definitions. As used herein the following terms shall have the following meanings:

“Obligations” means collectively all of the obligations and undertakings which are guaranteed by Guarantor and described in subsections (a) and (b) of Section 2 hereof.

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“Obligors” means the Company, Guarantor and any other endorsers, guarantors or obligors, primary or secondary, of any or all of the Obligations.

“Person” means any individual, firm, corporation, partnership, limited liability company, trust, joint venture, governmental entity or other entity.

Section 2.               Guaranty.

(a)           Guarantor hereby irrevocably, absolutely, and unconditionally guarantees to Newfield the prompt, complete, and full payment when due, and no matter how the same shall become due, of:

(i)all amounts due Newfield by the Company under the Agreements; and

(ii)any and all other indebtedness or liabilities which the Company may at any time owe to Newfield on account of or relating to the Agreements or any of them, whether incurred heretofore or hereafter or concurrently herewith, voluntarily, whether owed alone or with others, and whether fixed, contingent, absolute, inchoate, liquidated or unliquidated.

(b)           Guarantor hereby irrevocably, absolutely and unconditionally guarantees to Newfield the prompt, complete and full performance, when due, and no matter how the same shall become due, of aU obligations and undertakings of the Company to Newfield under, by reason of, or pursuant to any of the Agreements.

(c)           If the Company shall for any reason fail to pay any Obligation, as and when such Obligation shall become due and payable, Guarantor will, forthwith upon demand by Newfield, pay such Obligations in full to Newfield. If the Company shall for any reason fail to promptly perform any Obligations, Guarantor will, foahwith upon demand by Newfield, as applicable (to be determined by the action demanded of Guarantor by Newfield), perform the Obligations or pay the amount of damages recoverable under the Agreements, if any, on account of such non-performance.

(d)           Guarantor shall be primarily liable hereunder for the payment and performance of the Obligations.

Section 3.               Unconditional Guaranty.

(a)           No action which Newfield may take or omit to take in connection with any of the Agreements or any of the Obligations, and no course of dealing of Newfield with any Obligor or any other Person, shall release or diminish Guarantor’s Obligations, liabilities, agreements, or duties hereunder, nor shall the same affect this Guaranty in any way or afford Guarantor any recourse against Newfield, regardless of whether any such action or inaction may increase the risks to or liabilities of Newfield or any Obligor. Without limiting the foregoing, Guarantor hereby expressly agrees that Newfield may, from time to time, without notice to or the consent of Guarantor:

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(i)            amend, change or modify, in whole or in part, any one or more of the Agreements (with the agreement of the Company), and give or refuse to give any waivers or other indulgences with respect thereto;

(ii)           neglect, delay, fail, or refuse: to take or prosecute any action for the enforcement of any of the Obligations, to bring suit against any Obligor or any other Person, or to take any other action concerning the Obligations or the Agreements

(iii)          change, rearrange, extend, or renew the time, terms, or manner for payment or performance of any one or more of the Obligations (with the agreement of the Company);

(iv)          compromise or settle any unpaid or unperformed Obligation or any other Obligation or amount due or owing, or claimed to be due or owing, under any one or more of the Agreements (with the agreement of the Company);

(v)           apply all monies received from any Obligor in any manner permitted under the Agreements as Newfield may determine to be in Newfield’s best interest, without in any way being required on account of this Guaranty to inarshall security or assets or to apply all or any part of such monies upon any particular Obligations.

(b)           No action or inaction of any Obligor or any other Person, and no change of law or circumstances, shall release or diminish Guarantor’s obligations, liabilities, agreements or duties hereunder, affect this Guaranty in any way, or afford Guarantor any recourse against Newfield. Without limiting the foregoing, the obligations, liabilities, agreements, and duties of Guarantor under this Guaranty shall not he released, diminished, impaired, reduced, or affected by the occurrence of any of the following, from time to time, even if occurring without notice to or without the consent of Guarantor:

(i)            any voluntary or involuntary liquidation, dissolution or sales of all or substantially all assets, marshalling of assets or liabilities, receivership, conservatorship, assignment for the benefit of creditors, insolvency, bankruptcy, reorganization, arrangement, or composition of any Obligor or any of the assets of any Obligor under laws for the protection of debtors, or any discharge, impairment, modification, release, or limitation of the liability of, or stay of actions or lien enforcement proceedings against, any Obligor, any properties of any Obligor, or the estate in bankruptcy or any Obligor in the course of or resulting from any such proceedings;

(ii)           the failure by Newfield to file or enforce a claim in any proceeding described in the immediately preceding subsection (i) or to take any other action in any proceeding to which any Obligor is a party;

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(iii)          the release by operation of law of the Company in any proceeding described in subsection (i) or any similar proceeding, or the release of any other Obligor from any of the Obligations or any other obligations to Newfield; or

(iv)          the fact that Guarantor may have incurred directly part of the Obligations or is otherwise primarily liable therefor.

(c)           Newfield may invoke the benefits of this Guaranty before pursuing any remedies against any Obligor or any other Person for the payment or performance of any of the Obligations. Newfield may maintain an action against Guarantor on this Guaranty without joining any other Obligor therein and without bringing separate action against any other Obligor.

(d)           If payment to Newfield of any Obligation is held to constitute a preference or a voidable transfer under applicable state or federal laws, or if for any other reason Newfield is required to refund such payment to the payor thereof or to pay the amount thereof to any other Person, such payment to Newfield shall not constitute a release of Guarantor from any liability hereunder, and Guarantor agrees to pay such amount to Newfield on demand and agrees and acknowledges that this Guaranty shall continue to be effective or shall be reinstated, as the case may be, to the extent of any such payment or payments.

(e)           This is a continuing guaranty and shall apply to and cover all Obligations and renewals and extensions thereof and substitutions therefor from time to time.

Section 4.               Waiver. Guarantor hereby waives, with respect to the Obligations and this Guaranty:

(a)notice of the incurrence of any Obligation by the Company;

(b)notice that Newfield, any Obligor, or any other Person has taken

relating thereto or that any Obligor is in default under any of the Agreements;

(c)   demand, presentment for payment, and notice of demand, dishonor, nonpayment, or nonperformance; and

(d)all other notices whatsoever.

Section 5.              Exercise of Remedies. Newfield shall have the right to enforce, from time to time, in any order and at Newfield’s sole discretion, any rights, powers and remedies which Newfield may have under the Agreements or otherwise, including, but not limited to, issues and profits, the exercise of remedies against personal property, or the enforcement of any assignment of leases, rentals, oil or gas production, or other properties or rights, whether real or personal, tangible or intangible; and Guarantor shall be liable to Newfield hereunder for any deficiency

52

resulting from the exercise by Newfield of any such right or remedy even though the rights which Guarantor may have against the Company or other Person may be destroyed or diminislied by the exercise of any such right or remedy. No failure on the part of Newfield to exercise, and no delay in exercising, any right hereunder or under any other Agreements shall operate as a waiver hereof or thereof, nor shall any single or partial exercise of any right preclude any other or further exercise thereof or the exercise of any other right. The rights, powers and remedies of Newfield provided herein and in the other are cumulative and are in addition to, and not exclusive of, any other rights, powers or remedies provided by law or in equity. The rights of Newfield hereunder ace not conditional or contingent on any attempt by Newfield to exercise any of its rights under any other Agreements against any Obligor or any other Person.

Section 6.              No Subrogation. Insofar as Guarantor and the Company are concerned, any payment hereunder by Guarantor shall be deemed a contribution to the capital of the Company, and Guarantor shall have no right of subrogation, contribution, reimbursement, indemnification exoneration and any other remedy which Guarantor may have against Company or any other Person with respect to this Guaranty or the duties of Guarantor under the other Agreements or applicable law. Guarantor hereby irrevocably agrees, to the fullest extent permitted by law, that it will not exercise (and herein waives) any rights against any Company or any other Person which it may acquire by way of subrogation, contribution, reimbursement, indemnification or exoneration under or with respect to this Guaranty, the other Agreements or applicable law, by any payment made hereunder or otherwise. If the foregoing waivers are adjudicated unenforceable by a court of competent jurisdiction, then Guarantor agrees that no liability or obligation of the Company that shall accrue by virtue of any right to subrogation, contribution, indemnity, reimbursement or exoneration shall be paid, nor shall any such liability or transaction be deemed owed, until all of the Obligations shall have been paid in full.

Section 7.              Successors and Assigns. Guarantor’s rights or obligations hereunder may not be assigned or delegated, but this Guaranty and such obligations shall pass to and be fully binding upon the successors of the Guarantor, as well as Guarantor. This Guaranty shall apply to and inure to the benefit of Newfield and its successors or assigns. Without limiting the generality of the immediately preceding sentence, Newfield may assign, grant a participation in, or otherwise transfer any Obligation held by it or any portion thereof under any Agreements, to any other Person, and such other Person shall thereupon become vested with all of the benefits in respect thereof granted to Newfield hereunder with respect to the Obligation or portion thereof assigned by Newfield to such other Person.

Section 8.              Representations and Warranties. Guarantor hereby represents and warrants as follows:

(a)      the “WHEREAS” recitals at the beginning of this Guaranty are true and correct in all respects;

(b)     the execution, delivery and performance of this Guaranty by the Guarantor has been duly authorized in all material respects by all necessary limited partnership action on the part of Guarantor pursuant to the Guarantor’s certificate of limited partnership, limited partnership agreement, other constituent documents and/or applicable law, the execution and delivery of this Guaranty by the general partner executing this Guaranty oil behalf of the General Partner below has been duly authorized in all material

53

respects by all necessary corporate or similar action on the part of the general partner or general partners of the Guarantor, and written documentation (in the form of certified resolutions, other certificates or other documentation reasonably satisfactory to Newfield) shall be provided to Newfield upon its request;

(c)      the value of the consideration received and to be received by Guarantor in connection herewith is reasonably worth at least as much as the liability and Obligations of Guarantor hereunder, and the incurrence of such liability and obligations in return for such consideration may reasonably be expected to benefit Guarantor, directly or indirectly; and

(d)     Guarantor is not “insolvent” on the date hereof (that is, the sum of Guarantor’s absolute and contingent liabilities, including the Obligations, does not exceed the fair market value of Guarantor’s assets). Guarantor’s capital is adequate for the business in which Guarantor is engaged and intends to be engaged. Guarantor has not hereby incurred, nor does Guarantor intend to incur or believe that it will incur, debts which will be beyond its ability to pay as such debts mature.

Section 9.              Governing Law. This Guaranty is to be performed in the state of Texas and shall be governed by and construed and enforced in accordance with the laws of such state applicable to contracts made to be performed entirely within such state. Guarantor hereby irrevocably submits itself to the non-exclusive jurisdiction of the state and federal courts of the State of Texas, County of Harris, and agrees and consents that service of process may be made upon it in any legal proceeding related hereto by serving the Secretary of State of the State of Texas (or by other service) in accordance with applicable provisions of the Texas revised civil statutes, as amended, governing service of process upon foreign limited partnerships.

Section 10.            Invalidity of Particular Provisions. If any term or provision of this Guaranty shall be determined to be illegal or unenforceable, all other terms and provisions hereof shall nevertheless remain effective and shall be enforced to the fullest extent permitted by applicable law.

Section 11.            Headings and References. The headings used herein are for purposes of convenience only and shall not be used in construing the provisions hereof. The words “hereof”, “herein” and similar words refer to this Guaranty as a whole and not to any particular subdivision unless expressly so limited. The word “or” is not exclusive. Pronouns in masculine, feminine and neuter genders shall be construed to include any other gender, and words in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires.

Section 12.            Term. This Guaranty shall be irrevocable until all of the Obligations have been completely and finally paid and performed.

Section 13.            Limitation on Interest. Newfield and Guarantor intend to contract in strict compliance with applicable usury law from time to time in effect, and provisions of the Agreement limiting the interest for which Guarantor is obligated are expressly incorporated herein by reference.

Section 14.            Counterparts. This Guaranty may be executed in any number of counterparts, each of which when so executed shall he deemed to constitute one and the same

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Guaranty.

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IN WITNESS WHEREOF, Guarantor has executed and delivered this Guaranty as of the date first written above.

MARKWEST ENERGY PARTNERS, L.P.
By: MarkWest Energy GP, LLC, its General Partner
	By:	/s/ Frank Semple
	Name:	Frank Semple
	Title:	President & CEO

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SCHEDULE 1

TO

Guaranty dated of

MarkWest Energy Partners, L.P. in favor of Newfield Exploration Mid-Continent Inc.

AGREEMENTS

CONSTRUCTION, OPERATION AND GAS GATHERING AGREEMENT dated entered into by and between Newfield Exploration Mid-Continent Inc., as Producer, and MarkWest Western Oklahoma Gas Company, L.L.C., as Gatherer.

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EX-31.1

Exhibit 31.1

CERTIFICATION

I, Frank M. Semple, certify that:

1. I have reviewed this quarterly report on Form 10-Q of MarkWest Hydrocarbon, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information;

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: November 6, 2006	By:	/s/ FRANK M. SEMPLE
		Frank M. Semple
		Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Nancy K. Buese, certify that:

1. I have reviewed this quarterly report on Form 10-Q of MarkWest Hydrocarbon, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15-d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information;

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: November 6, 2006	By:	/s/ NANCY K. BUESE
		Nancy K. Buese
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of MarkWest Hydrocarbon, Inc. (the “Company”) on Form 10-Q for the period ending September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Frank M. Semple, Chief Executive Officer of the Company, certify, to the best of my knowledge, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ FRANK M. SEMPLE

Frank M. Semple

Chief Executive Officer

November 6, 2006

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of MarkWest Hydrocarbon, Inc. (the “Company”), on Form 10-Q for the period ending September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Nancy K. Buese, Chief Financial Officer of the Company, certify, to the best of my knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ NANCY K. BUESE

Nancy K. Buese

Chief Financial Officer

November 6, 2006