UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

For the transition period from              to               

 

Commission File Number 1-11566

 

 

 

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

Yes   ý        No   o

 

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

Yes   o        No   ý

 

The registrant had 9,371,337 shares of common stock, $.01 per share par value, outstanding as of June 30, 2003.

 

 

PART I–FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
			Consolidated Balance Sheets at June 30, 2003 and December 31, 2002
			Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2003 and 2002
			Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002
			Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2003
			Notes to the Consolidated Financial Statements
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.		Quantitative and Qualitative Disclosures about Market Risk
Item 4.		Controls and Procedures
PART II–OTHER INFORMATION
Item 1.		Legal Proceedings
Item 4.		Submission of Matters to a Vote of Security Holders
Item 6.		Exhibits and Reports on Form 8-K
SIGNATURE

 

Glossary of Terms

 

Bcf		billion cubic feet of natural gas
Btu		British thermal units, an energy measurement
LIBOR		London Inter-Bank Offering Rate
Mcf		thousand cubic feet of natural gas
Mcf/d		thousand cubic feet of natural gas per day
Mcfe		thousand cubic feet of natural gas equivalent
Mcfe/d		thousand cubic feet of natural gas equivalent per day
MMBtu		million British thermal units, an energy measurement
MMcf		million cubic feet of natural gas
MMcf/d		million cubic feet of natural gas per day
NGLs		natural gas liquids, such as propane, butanes and natural gasoline
One barrel of oil or NGLs is the energy equivalent of six Mcf of natural gas.

 

 

PART 1–FINANCIAL INFORMATION

Item 1.   Consolidated Financial Statements

 

MARKWEST HYDROCARBON, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(In thousands, excepts share and per share data)

 

		June 30, 2003			December 31, 2002
ASSETS
Current assets:
Cash and cash equivalents		$	31,302		$	6,410
Receivables, net (including related party receivables of $2,420 and $748, respectively)		22,536			25,444
Inventories		4,911			4,347
Prepaid replacement natural gas		741			1,197
Other assets		1,458			1,240
Total current assets		60,948			38,638
Property, plant and equipment:
Gas processing, gathering, storage and marketing equipment		160,745			121,851
Oil and gas properties and equipment, full cost method		131,996			139,234
Land, buildings and other equipment		7,156			7,540
Construction in progress		2,071			1,610
		301,968			270,235
Less: accumulated depreciation, depletion and amortization		(66,257		)	(58,717		)
Total property and equipment, net		235,711			211,518
Risk management asset		490			749
Intangible assets, net of accumulated amortization of $2,709 and $2,018, respectively		2,071			2,138
Note receivables from employees		247			271
Total assets		$	299,467		$	253,314
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable (including related party payables of $1,406 and $1,264, respectively)		$	25,287		$	26,063
Accrued liabilities		21,075			8,145
Risk management liability		13,696			13,719
Total current liabilities		60,058			47,927
Deferred income taxes		33,234			35,685
Long-term debt		79,904			64,223
Risk management liability		1,463			2,115
Other long-term liabilities		6,544			4,011
Minority interest in consolidated subsidiary		52,341			46,001
Commitments and contingencies (see Note 8)
Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, 0 shares outstanding		—			—
Common stock, par value $0.01, 22,000,000 shares authorized, 9,442,968 and 9,417,511 shares issued, respectively		94			94
Additional paid-in capital		42,921			42,751
Retained earnings		28,630			19,693
Accumulated other comprehensive income (loss), net of tax		(5,321		)	(8,858		)
Treasury stock, 71,631 and 55,507 shares, respectively		(401		)	(328		)
Total stockholders’ equity		65,923			53,352
Total liabilities and stockholders’ equity		$	299,467		$	253,314

 

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

 

1

 

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(in thousands, except per share data)
Revenue:
Gathering, processing and marketing		$	47,888		$	38,560		$	98,539		$	75,890
Exploration and production		9,233			7,409			19,892			14,466
Total revenue		57,121			45,969			118,431			90,356
Operating expenses:
Purchased product costs		44,357			32,257			90,360			60,345
Facility expenses		4,548			3,776			9,054			8,171
Lease operating		2,115			1,378			3,723			2,560
Transportation costs		502			383			1,015			745
Production taxes		614			497			1,342			780
Selling, general and administrative expenses		3,646			2,725			6,783			5,551
Depreciation, depletion and amortization		6,040			4,924			11,138			10,138
Gain on sale of oil and gas properties		(19,692		)	—			(19,692		)	—
Total operating expenses		42,130			45,940			103,723			88,290
Income from operations		14,991			29			14,708			2,066
Other income and (expenses):
Interest income		20			15			44			22
Interest expense		(2,018		)	(1,190		)	(3,105		)	(2,242		)
Write-down of deferred financing costs		—			(2,259		)	—			(2,977		)
Gain on sale to related party (Note 5)		188			64			188			64
Minority interest in net income of consolidated subsidiary		(861		)	(358		)	(1,735		)	(358		)
Other income (expense)		(1		)	(27		)	(16		)	(26		)
Income (loss) before income taxes		12,319			(3,726		)	10,084			(3,451		)
Provision (benefit) for income taxes:
Current		3,693			(150		)	3,670			(67		)
Deferred		(1,353		)	(1,501		)	(2,552		)	(1,486		)
Provision (benefit) for income taxes		2,340			(1,651		)	1,118			(1,553		)
Income (loss) before change in accounting principle		9,979			(2,075		)	8,966			(1,898		)
Cumulative effect of change in accounting for asset retirement obligations, net of tax		—			—			(29		)	—
Net income (loss)		$	9,979		$	(2,075	)	$	8,937		$	(1,898	)
Basic earnings (loss) per share of common stock		$	1.07		$	(0.22	)	$	0.96		$	(0.20	)
Earnings (loss) per share assuming dilution		$	1.06		$	(0.22	)	$	0.95		$	(0.20	)
Weighted average number of outstanding shares of common stock:
Basic		9,351			9,369			9,356			9,365
Assuming dilution		9,371			9,402			9,376			9,390

 

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

 

2

 

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

		Six Months Ended June 30,
		2003			2002
		(in thousands)
Cash flows from operating activities:
Net income (loss)		$	8,937		$	(1,898	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of change in accounting principle		29			—
Depreciation, depletion and amortization		11,138			10,138
Amortization of deferred financing costs included in interest expense		813			705
Write-off of deferred financing costs		—			2,977
Minority interest in net income of consolidated subsidiary		1,735			358
Derivative ineffectiveness and non-cash mark-to-market adjustments		(1,475		)	(149		)
Reclassification of Enron hedges to purchased gas costs		(154		)	(560		)
Deferred income taxes		(2,552		)	(1,486		)
Gain on sale of San Juan Basin properties		(19,692		)	—
Other		237			1
Changes in operating assets and liabilities:
(Increase) decrease in receivables		10,763			1,371
(Increase) decrease in inventories		(897		)	1,616
(Increase) decrease in prepaid expenses and other assets		388			8,117
Increase (decrease) in accounts payable and accrued liabilities		2,310			3,597
Increase (decrease) in other long-term liabilities		—			3,090
Net cash flow provided by operating activities		11,580			27,877
Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired		(38,238		)	—
Proceeds from sale of San Juan Basin properties, net of costs to dispose		49,470			—
Capital expenditures		(14,023		)	(16,311		)
Proceeds from sale of assets		105			263
Proceeds from sale of assets to related parties		229			186
Net cash used in investing activities		(2,457		)	(15,862		)
Cash flows from financing activities:
Proceeds from long-term debt		68,235			33,400
Repayment of long-term debt		(56,424		)	(87,944		)
Proceeds from initial public offering, net		—			43,000
Proceeds from private placement of MarkWest Energy Partners’ common units, net		7,807			—
Debt issuance costs		(809		)	(1,651		)
Distributions to MarkWest Energy Partners’ unitholders		(3,242		)	—
Exercise of stock options		167			—
Net issuance (buyback) of treasury shares		(70		)	111
Payment on share purchase notes		—			13
Net cash provided by (used in) financing activities		15,664			(13,071		)
Effect of exchange rate on changes in cash		105			17
Net increase (decrease) in cash and cash equivalents		24,892			(1,039		)
Cash and cash equivalents at beginning of period		6,410			2,340
Cash and cash equivalents at end of period		$	31,302		$	1,301

 

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

 

3

 

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(UNAUDITED)

 

		Shares of Common Stock		Shares of Treasury Stock		Common Stock			Additional Paid-In Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
		(in thousands)
Balance, December 31, 2002		8,561		(50	)	$	86		$	42,759		$	19,693		$	(328	)	$	(8,858	)	$	53,352
Stock dividend, retroactively applied to January 1, 2003		859		(5	)	8			(8		)	—			—			—			—
Comprehensive income:
Net income		—		—		—			—			8,937			—			—			8,937
Other comprehensive income:
Foreign currency translation, net of tax		—		—		—			—			—			—			4,061			4,061
Risk management activities, net of tax		—		—		—			—			—			—			(524		)	(524		)
Comprehensive income, net of tax																					12,474
Acquisition of treasury stock, net		—		(17	)	—			3			—			(73		)	—			(70		)
Exercise of options		23		—		—			167			—			—			—			167
Balance, June 30, 2003		9,443		(72	)	$	94		$	42,921		$	28,630		$	(401	)	$	(5,321	)	$	65,923

 

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

 

4

 

MARKWEST HYDROCARBON, INC

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

1.              General

 

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

 

We have prepared the unaudited financial statements presented herein in accordance with the instructions to Form 10-Q. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States. Please read the interim consolidated financial statements in conjunction with the Consolidated Financial Statements and attached notes for the year ended December 31, 2002, included in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission. In the opinion of management, we have made all necessary normal recurring adjustments for a fair statement of the results for the unaudited interim periods.

 

We base the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate. The effective tax rate varies from statutory rates primarily due to permanent differences in Canada and percentage depletion in excess of basis in the U.S.

 

2.              Sale of San Juan Basin Properties

 

On June 30, 2003, MarkWest Hydrocarbon completed the sale of the majority of its San Juan Basin oil and gas properties to XTO Energy Inc. for approximately $49.8 million, net of anticipated transaction costs and closing adjustments. MarkWest Hydrocarbon expects to close on the remaining properties, valued at approximately $6.1 million, upon receipt of necessary consents, in the near future. We recognized a net pretax gain of $19.7 million on the sale completed June 30, 2003.  The proceeds from the sale were used to repay debt outstanding under our credit facility in the amount of approximately $42.6 million. The remaining proceeds will be used for general corporate purposes.

 

3.              Pinnacle Acquisition

 

On March 28, 2003, our consolidated subsidiary, MarkWest Energy Partners, L.P. (“MarkWest Energy Partners”), completed the acquisition (the “Pinnacle Acquisition”) of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, the “Sellers”). The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness.

 

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

 

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

 

Acquisition costs:
Long-term debt incurred		$	39,471
Direct acquisition costs		450
Current liabilities assumed		8,150
Total		$	48,071
Allocation of acquisition costs:
Current assets		$	10,643
Fixed assets (including long-term contracts)		37,428
Total		$	48,071

 

5

 

Pro Forma Results of Operations (Unaudited)

 

The following table reflects the unaudited pro forma consolidated results of operations for the three and six months ended June 30, 2003 and 2002, as though the Pinnacle Acquisition had occurred on January 1, 2002. These unaudited pro forma results have been prepared for comparative purposes only and are not necessarily indicative of future results.

 

		Three Months Ended June 30, 2002			Six Months Ended June 30,
					2003			2002
		(in thousands, except per share data)
Revenue		$	57,136		$	136,250		$	109,565
Income (loss) before change in accounting principle		$	(2,218	)	$	9,681		$	(1,908	)
Net income (loss)		$	(2,218	)	$	9,652		$	(1,908	)
Basic net income (loss) per share		$	(0.24	)	$	1.03		$	(0.20	)
Diluted net income (loss) per share		$	(0.24	)	$	1.03		$	(0.20	)

 

4.              Private Placement

 

Our consolidated subsidiary, MarkWest Energy Partners, sold 375,000 common units in two installments at a price of $26.23 per unit in a private placement to certain accredited investors. The first installment of 300,031 units was completed on June 27, 2003, and grossed approximately $7.9 million. The second installment of 74,969 units was completed on July 10, 2003, and grossed approximately $1.9 million. MarkWest Energy Partners’ general partner paid its pro rata contribution in July 2003 after the second installment was completed. MarkWest Energy Partners primarily used the proceeds to pay down debt under its credit facility.

 

5.              Related Party Transactions

 

MarkWest Hydrocarbon, Inc.

 

Through our wholly owned subsidiary, MarkWest Resources, Inc. (“Resources”), we held varied undivided interests in several exploration and production assets in which MAK-J Energy Partners Ltd. (“MAK-J”) also owns an undivided interest, varying from 25% to 51%. The general partner of MAK-J is a corporation owned and controlled by our President and Chief Executive Officer. One current officer and one former officer, who left the Company on July 31, 2003, are limited partners in MAK-J. Joint property acquisitions and joint operating agreements are subject to the approval of independent members of our Board of Directors. The properties were operated pursuant to joint operating agreements entered into between Resources and MAK-J. Resources was the operator under such agreements. The joint operating agreements are governed by a Participation and Operations Agreement, most recently amended June 2, 2003. As the operator, Resources was obligated to provide certain accounting and well operations services to the parties. The Participation and Operations Agreement provided for a monthly fee ($2,000 per month) payable to Resources to offset the costs of accounting and well operations on a monthly basis. As a part of the sale of oil and gas properties to XTO Energy on June 30, 2003, the Participation and Operations Agreement was assigned to XTO Energy.

 

Through our wholly owned subsidiary, Matrex, LLC, we hold interests in certain exploration and production assets in which MAK-J also owns interests.  Both parties are participants to joint operating agreements involving other third parties.

 

From time to time, MarkWest Hydrocarbon has entered into hedges with counterparties on behalf of MAK-J. MarkWest Hydrocarbon billed or remitted to MAK-J, as circumstances dictated, its portion of transaction costs and settlements on a monthly basis. As of July 2003, all such hedges had been settled.

 

6

 

As of June 30, 2003, we have receivables due from MAK-J, representing its share of operating and capital costs generated in the normal course of business, of approximately $2.4 million. We also have payables to MAK-J, representing its share of revenues generated in the normal course of business, of approximately $1.4 million as of June 30, 2003. Due to a difference in the timing of when MAK-J paid us (prior to June 30, 2003) for its portion of hedges settled in conjunction with the sale of our San Juan Basin properties and when we paid the counter parties (after June 30, 2003), we recorded a related $2.5 million account payable to the counter party as of June 30, 2003.

 

MarkWest Energy Partners

 

On April 17, 2003, MarkWest Hydrocarbon sold a 1% interest in MarkWest Energy GP, L.L.C., the general partner of MarkWest Energy Partners, and 4,000 of its MarkWest Energy Partners subordinated units to an officer for approximately $26,000 and $76,000, respectively.

 

On June 19, 2003, MarkWest Hydrocarbon sold a 0.6% interest in the general partner of MarkWest Energy Partners and 3,500 of its MarkWest Energy Partners subordinated units to two MarkWest Hydrocarbon employees for approximately $25,000 and $77,000, respectively.

 

For each transaction, proceeds received in excess of our book value in our investment in MarkWest Energy GP, L.L.C., and MarkWest Energy Partners subordinated units was recorded as a gain on sale to related party on our Statement of Operations.

 

6.              Dispositions

 

Our board of directors has approved a plan to sell any of our three NGL product terminals, which are considered to be non-strategic assets. On July 15, 2003, we sold our Lordstown, Ohio terminal to a third party for $0.8 million, including $0.2 million for on-hand inventory. On August 6, 2003, we entered into a purchase and sale agreement with a third party to sell our Lynchburg, Virginia terminal for approximately $1.6 million plus on-hand inventory as of the closing date, which is expected to occur in September 2, 2003. We believe the results from these terminals are immaterial for separate presentation as a discontinued operation.

 

7.              Segment Reporting

 

Our operations are classified into three reportable segments:

 

(1)          Exploration and Production—explore for and produce natural gas;

(2)          Gathering and Processing—gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids.  Our gathering and processing operations are conducted by MarkWest Energy Partners; and

(3)          Marketing—sell our equity and third party NGLs and purchase and market third-party natural gas.

 

On May 24, 2002, we spun off our gathering and processing assets into MarkWest Energy Partners, our fully consolidated subsidiary. The formation and initial public offering (the “IPO”) of MarkWest Energy Partners (the IPO closed on May 24, 2002) and the subsequent change to the structure of our internal organization caused the composition of our reportable segments to change in the fourth quarter of 2002. Prior to the fourth quarter of 2002, we classified our operations into two reportable segments:

 

(1)          Exploration and Production—explore for and produce natural gas; and

(2)          Gathering, Processing and Marketing—gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids; also purchase and market third-party natural gas and NGLs.

 

Although the three and six months ended June 30, 2003 reflects our new segments, information prior to May 24, 2002, has not been restated to reflect the change in segmentation because no transfer pricing existed between Gathering and Processing and Marketing up until that point in time. In connection with the formation of MarkWest Energy Partners, certain contracts were executed which established the basis of fees for services rendered by processing MarkWest Hydrocarbon’s natural gas. No such arrangement existed prior to the formation of MarkWest

 

7

 

Energy Partners. As a result, it is not practicable to restate certain prior period segment information to conform to our current presentation.

 

We evaluate the performance of our segments and allocate resources to them based on operating income.  There were no intersegment revenues prior to May 24, 2002. We conduct our business in the United States and Canada.

 

The tables below presents information about operating income for the reported segments for the three and six months ended June 30, 2003 and 2002. Operating income for each segment includes total revenues less purchased products costs, operating expenses, depreciation and depletion and excludes selling, general and administrative expenses, interest expense, interest income, one-time charges and income taxes.

 

		MarkWest Hydrocarbon
		Exploration and Production									Marketing			MarkWest Energy Partners			Total
														Gathering & Processing
		U.S.			Canada			Total			U.S.			U.S.
		(in thousands)
Three Months Ended June 30, 2003
Revenues		$	3,582		$	5,651		$	9,233		$	18,252		$	29,636		$	57,121
Segment operating income (loss)		$	1,572		$	435		$	2,007		$	(7,248	)	$	4,186		$	(1,055	)

 

		Exploration and Production									Gathering Processing & Marketing			Total
		U.S.			Canada			Total			U.S
		(in thousands)
Three Months Ended June 30, 2002
Revenues		$	2,386		$	5,023		$	7,409		$	38,560		$	45,969
Segment operating income		$	1,059		$	1,052		$	2,111		$	643		$	2,754

 

8

 

 

		MarkWest Hydrocarbon
		Exploration and Production									Marketing			MarkWest Energy Partners			Total
														Gathering & Processing
		U.S.			Canada			Total			U.S.			U.S.
		(in thousands)
Six Months Ended June 30, 2003
Revenues		$	7,824		$	12,068		$	19,892		$	51,210		$	47,329		$	118,431
Segment operating income (loss)		$	3,532		$	2,713		$	6,245		$	(12,251	)	$	7,805		$	1,799

 

		Exploration and Production									Gathering Processing & Marketing			Total
		U.S.			Canada			Total			U.S
		(in thousands)
Six Months Ended June 30, 2002
Revenues		$	4,743		$	9,723		$	14,466		$	75,890		$	90,356
Segment operating income		$	1,908		$	1,264		$	3,172		$	4,445		$	7,617

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(in thousands)
Total segment operating income (loss)		(1,055		)	$	2,754		1,799			$	7,617
Gain on sale of oil and gas properties		19,692			—			19,692			—
Selling, general and administrative expenses		(3,646		)	(2,725		)	(6,783		)	(5,551		)
Interest income		20			15			44			22
Interest expense		(2,018		)	(1,190		)	(3,105		)	(2,242		)
Write-off of deferred financing costs		—			(2,259		)	—			(2,977		)
Gain on sale to related party		188			64			188			64
Minority interest in net income of consolidated subsidiary		(861		)	(358		)	(1,735		)	(358		)
Other income (expense)		(1		)	(27		)	(16		)	(26		)
Income (loss) before taxes		$	12,319		$	(3,726	)	$	10,084		$	(3,451	)

 

9

 

8.              Commitments and Contingencies

 

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

 

9.              Stock and Unit Compensation

 

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

 

Had compensation cost for our two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123 our net income and earnings (loss) per share would have been changed to the pro forma amounts listed below:

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
		(in thousands, except per share data)
Net income (loss), as reported		$	9,979		$	(2,075	)	$	8,937		$	(1,898	)
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect		(111		)	(76		)	(184		)	(150		)
Pro forma net income (loss)		$	9,868		$	(2,151	)	$	8,753		$	(2,048	)
Earnings (loss) per share:
Basic, as reported		$	1.07		$	(0.22	)	$	0.96		$	(0.20	)
Basic, pro forma		$	1.05		$	(0.23	)	$	0.94		$	(0.22	)
Diluted, as reported		$	1.06		$	(0.22	)	$	0.96		$	(0.20	)
Diluted, pro forma		$	1.05		$	(0.23	)	$	0.93		$	(0.22	)

 

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

 

10.       Asset Retirement Obligations

 

On January 1, 2003, we adopted SFAS No. 143, Asset Retirement Obligations.  SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost will be allocated to expense using a systematic and rational method. During the first quarter of 2003, we recorded a net-of-tax cumulative effect of change in accounting principle charge of $29,000 ($63,000 before tax), an asset retirement obligation of $3.4 million (a net increase to long-term liabilities of $2.5 million). We also increased net properties $2.4 million in accordance with the provisions of SFAS No. 143. There was no impact on our cash flows as a result of adopting SFAS No. 143. The pro forma asset retirement obligation would have been $2.5 million at January 1, 2002 had we adopted SFAS No. 143 on January 1, 2002. The asset retirement obligation, which is included on the Consolidated Balance Sheet in Other Long-Term Liabilities, was $3.3 million at June 30, 2003.

 

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For the periods ended June 30, 2002, the pro forma effect on net income and earnings per share, had we adopted SFAS No. 143 on January 1, 2002, would have been as follows:

 

		Three Months Ended June 30, 2002						Six Months Ended June 30, 2002
		As Reported			Pro Forma			As Reported			Pro Forma
		(in thousands, except per share data)
Net loss		$	(2,075	)	$	(2,425	)	$	(1,898	)	$	(2,600	)
Loss per share:
Basic		$	(0.22	)	$	(0.26	)	$	(0.20	)	$	(0.28	)
Diluted		$	(0.22	)	$	(0.26	)	$	(0.20	)	$	(0.28	)

 

The following is a reconciliation of the asset retirement obligation for the period ended June 30, 2003 (in thousands):

 

Asset retirement obligation as of January 1, 2003		$	3,367
Liability accrued upon capital expenditures		268
Liability settled		(403		)
Accretion of discount expense		45
Asset retirement obligation as of June 30, 2003		$	3,277

 

11.       Recent Accounting Pronouncements

 

Statement of Financial Accounting Standards No. 141, Business Combinations (“FAS 141”) and Statement of Financial Accounting Standards, No. 142, Goodwill and Intangible Assets (“FAS 142”) were issued by the Financial Accounting Standards Board (“FASB”) in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively.  FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method.  Additionally, FAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets.  FAS 142 establishes new guidelines for accounting for goodwill and other intangible assets.  Under FAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment.  The FASB, the Securities and Exchange Commission (“SEC”) and others continue to discuss the appropriate application of FAS 141 and 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves.  Depending on the outcome of such discussions, these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets.  In addition, the disclosures required by FAS 141 and 142 relative to intangibles would be included in the notes to financial statements.  Historically, we, like many other oil and gas companies, have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after FAS 141 and 142 became effective.

 

As applied to companies like us that have adopted full cost accounting for oil and gas activities, we understand that this interpretation of FAS 141 and 142 would only affect our balance sheet classification of proved oil and gas leaseholds acquired after June 30, 2001 and our unproved oil and gas leaseholds.  Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with full cost accounting rules.

 

As of June 30, 2003, we had undeveloped leaseholds of approximately $25.6 million that would be classified on our balance sheet as “intangible undeveloped leasehold” if we applied the interpretations currently being discussed.

 

We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

 

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12.       Subsequent Events

 

On July 10, 2003, our board of directors declared a stock dividend of one share of MarkWest Hydrocarbon’s common stock for each of ten shares of common stock held by our shareholders. The stock dividend was paid on August 11, 2003, to the stockholders of record as of the close of business on July 31, 2003. All periods presented were adjusted to give effect to the stock dividend.

 

On July 31, 2003, MarkWest Hydrocarbon’s consolidated subsidiary, MarkWest Energy Partners, entered into a Purchase and Sale Agreement to purchase a 68-mile intrastate gas transmission pipeline near Lubbock, Texas for approximately $12 million. The transaction is expected to close on September 1, 2003, and it will be financed through its existing credit line.

 

Only July 14, 2003, MarkWest Energy Partners was notified of the bankruptcy filing of Mirant Inc. MarkWest Energy Partners is party to a long-term fixed transport fee arrangement with one Mirant Inc.’s wholly owned subsidiaries that provides electrical power to ERCOT power grid. Depending upon the outcome of the bankruptcy filings and the subsequent legal proceedings that follow, payment of MarkWest Energy Partners’ monthly transport fee of approximately $180,000 for transportation services may be impacted.

 

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

 

Forward-Looking Information

 

Statements included in this Management’s Discussion and Analysis that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as “may,” “believe,” “estimate,” “expect,” “plan,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events, activities or developments. Our actual results could differ materially from those discussed in our forward-looking statements.  Forward-looking statements include statements relating to, among other things:

 

•                  Our plans for pursuing future exploration projects

•                  Our production plans

•                  Our expectations regarding gas prices

•                  Our estimates of quantities of proven oil and gas reserves

•                  Our projections of rates of production and timing of development expenditures

•                  Our efforts to increase fee-based contract volumes

•                  Our ability to maximize the value of our NGL output

•                  The adequacy of our general public liability, property, and business interruption insurance

•                  Our ability to comply with environmental and governmental regulations

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

•                  Our ability to obtain waivers of non-compliance under our credit facility

•                  The success of our efforts to improve our liquidity position

 

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

 

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

•                  The availability and prices of NGL and competing commodities

•                  The effectiveness of our NGL hedging activities

•                  The availability and prices of raw natural gas supply

•                  Our ability to negotiate favorable marketing agreements

•                  The risks that third party or MarkWest Hydrocarbon’s natural gas exploration and production activities will not occur or be successful

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

•                  Competition from other NGL processors, including major energy companies

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

•                  Winter weather conditions

•                  Changes in foreign economics, currency, and laws and regulations in Canada where MarkWest Hydrocarbon has made direct investments

•                  Our ability to estimate quantities of proven oil and gas reserves

•                  Our ability to project rates of production

•                  Our ability to project the timing of developmental expenditures

•                  Our ability to manage the risks inherent in drilling wells

•                  The ability of the Partnership to make distributions to MarkWest Hydrocarbon and the other limited partners

 

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

 

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Sale of San Juan Basin Properties

 

On June 30, 2003, MarkWest Hydrocarbon completed the sale of the majority of its San Juan Basin oil and gas properties to XTO Energy Inc. for approximately $49.8 million, net of anticipated transaction costs and closing adjustments. MarkWest Hydrocarbon expects to close on the remaining properties, valued at approximately $6.1 million, upon receipt of necessary consents, in the near future. We recognized a net pretax gain of $19.7 million on the sale completed June 30, 2003. The proceeds from the sale were used to repay debt outstanding under our existing credit facility in the amount of approximately $42.6 million. The remaining proceeds will be used for general corporate purposes.

 

Pinnacle Acquisition

 

On March 28, 2003, our consolidated subsidiary, MarkWest Energy Partners, completed the Pinnacle Acquisition. The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness.

 

The acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of MarkWest Energy Partners as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the MarkWest Energy Partners entities, and all entities survived the merger. The assets acquired from the Sellers, primarily located in the state of Texas, with the balance located in New Mexico, Louisiana, Mississippi and Kansas, are comprised of three lateral natural gas pipelines and twenty gathering systems. The three lateral natural gas pipelines consist of approximately 67 miles of pipe and transport up to 1.1 Bcf/day under firm contracts to power plants. The twenty gathering systems gather more than 44 MMcf/d.

 

Extended Facility Maintenance

 

In addition to the routinely scheduled annual maintenance of MarkWest Energy Partners’ Kenova, Boldman and Cobb gas processing plants and the Siloam fractionator (all of which are located in Appalachia), additional maintenance was required at the Kenova and Cobb facilities during the second quarter of 2003. The additional downtime for the facilities curtailed throughput and related sales volumes and revenues.

 

Results of Operations

 

Operating Data

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2003		2002		% Change		2003		2002		% Change
Gathering, processing and marketing
Appalachia:
NGL product production—Siloam plant (gallons)		35,600,000		41,600,000		(14	)%	75,700,000		84,600,000		(11	)%
NGL product sales—Siloam plant(gallons)		30,900,000		34,200,000		(10	)%	84,900,000		91,400,000		(7	)%
Texas(1)
Pipeline throughput (Mcf/d)		42,000		—		NM		42,000		—		NM
Michigan:
Pipeline throughput (Mcf/d)		14,500		12,100		20	%	14,900		11,500		30	%
NGL product sales (gallons)		2,900,000		2,400,000		21	%	5,900,000		4,900,000		20	%
Exploration and production
Natural gas produced (Mcfe/d)		24,900		28,100		(11	)%	26,200		28,700		(9	)%

 

NM – Not meaningful

(1)  Acquired March 28, 2003, our MarkWest Pinnacle assets are located primarily in Texas and four surrounding states.

 

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Three Months Ended June 30, 2003 Compared to the Three Months Ended June 30, 2002

 

Net income. Net income was $10.0 million for the three months ended June 30, 2003, compared to a net loss of $2.1 million for the three months ended June 30, 2002. The $19.7 million pretax gain on sale of our San Juan Basin properties was the primary reason for the increase in net income.  Partially offsetting the gain on sale were negative operating margins from our keep-whole contract based business.

 

Gathering, processing and marketing revenue. Gathering, processing and marketing revenue was $47.9 million for the three months ended June 30, 2003 compared to $38.6 million for the three months ended June 30, 2002, an increase of $9.3 million, or 24%. The Pinnacle Acquisition increased revenues $16.7 million, partially offset by a reduction in gas marketing revenues of $8.3 million, a result of reduced volumes sold. Increased prices in our Appalachian percent-of-proceeds contract business and increased prices and throughput and sales volumes in our Michigan operations increased revenues $1.1 million.

 

Exploration and production revenue.  Exploration and production revenue was $9.2 million for the three months ended June 30, 2003 compared to $7.4 million for the three months ended June 30, 2002, an increase of $1.8 million, or 25%. A 38% company-wide realized sales price increase more than offset the 11% company-wide volume decrease.

 

Purchased product costs.  Purchased product costs were $44.4 million for the three months ended June 30, 2003, compared to $32.3 million for the three months ended June 30, 2002, an increase of $12.1 million, or 38%. The Pinnacle Acquisition increased purchased product costs $13.7 million, partially offset by a reduction in gas marketing purchased products costs of $7.3 million, a result of reduced volumes sold. Higher natural gas prices in our keep-whole contract based business increased purchased product costs $6.3 million.

 

Facility expenses.  Facility expenses were $4.5 million for the three months ended June 30, 2003, compared to $3.8 million for the three months ended June 30, 2002, an increase of $0.8 million, or 20%. Facility expenses increased primarily due to the Pinnacle Acquisition.

 

Lease operating expenses.  Lease operating expenses were $2.1 million for the three months ended June 30, 2003, compared to $1.4 million for the three months ended June 30, 2002, an increase of $0.7 million, or 53%. Lease operating expenses increased principally due to increased rental costs and workover and saltwater disposal expenses in Canada.

 

Transportation costs.  Transportation costs were $0.5 million for the three months ended June 30, 2003, compared to $0.4 million for the three months ended June 30, 2002, an increase of $0.1 million, or 31%. Transportation costs increased primarily due to increased production from our U.S. operations.

 

Production taxes.  Production taxes were $0.6 million for the three months ended June 30, 2003, compared to $0.5 million for the three months ended June 30, 2002, an increase of $0.1 million, or 24%. Production taxes increased principally due to increased natural gas prices in 2003.

 

Selling, general and administrative expenses.  Selling, general and administrative expenses were $3.6 million for the three months ended June 30, 2003, compared to $2.7 million for the three months ended June 30, 2002, an increase of $0.9 million, or 25%.  The increase is principally attributable to increased insurance costs and incremental costs associated with operating MarkWest Energy Partners as a public company.

 

Depreciation and depletion.  Depreciation and depletion were $6.0 million for the three months ended June 30, 2003, compared to $4.9 million, for the three months ended June 30, 2002, an increase of $1.1 million, or 23%. Depreciation and depletion increased due to the Pinnacle Acquisition and a mid-year revision of our Canadian reserves. With respect to our midyear Canadian reserve analysis, reserve increases from drilling during the first half of 2003 were offset by year-to-date production and a downward revision of certain reserves since year end.

 

Interest expense.  Interest expense was $2.0 million for the three months ended June 30, 2003, compared to $1.2 million for the three months ended June 30, 2002, an increase of $0.8 million, or 70%. The settlement of interest rate swaps increased interest expense $0.6 million.

 

15

 

Write-down of deferred financing costs. We wrote off $2.3 million in deferred financing costs in the second quarter of 2002 as a result of amending our credit facility in the second quarter of 2002.

 

Minority interest in net income of consolidated subsidiary. This represents the minority interest (i.e., non-MarkWest Hydrocarbon) ownership in the net income of MarkWest Energy Partners, which completed its initial public offering in May 2002.

 

Six Months Ended June 30, 2003 Compared to the Six Months Ended June 30, 2002

 

Net income. Net income was $8.9 million for the six months ended June 30, 2003, compared to a net loss of $1.9 million for the six months ended June 30, 2002. The $19.7 million pretax gain on sale of our San Juan Basin properties was the principal reason for the increase in net income. Partially offsetting the gain on sale were negative operating margins, including hedging losses, from our keep-whole contract based business.

 

Gathering, processing and marketing revenue. Gathering, processing and marketing revenue was $98.5 million for the six months ended June 30, 2003 compared to $75.9 million for the six months ended June 30, 2002, an increase of $22.6 million, or 30%. Revenue was higher in 2003 than in 2002 primarily due to:

 

•                  The Pinnacle Acquisition added $17.5 million.

•                  Increased NGL product sales prices offset volume decreases in Appalachia adding $11.6 million in revenue, net of $9.7 million of hedging losses in 2003.

•                  Gas marketing volumes declined primarily due to reduced volumes sold decreasing revenue $7.7 million.

 

Exploration and production revenue. Exploration and production revenue was $19.9 million for the six months ended June 30, 2003 compared to $14.5 million for the six months ended June 30, 2002, an increase of $5.4 million, or 38%. Company-wide realized sales price increases more than offset the 10% company-wide volume decrease.

 

Purchased product costs.  Purchased product costs were $90.4 million for the six months ended June 30, 2003, compared to $60.3 million for the six months ended June 30, 2002, an increase of $30.0 million, or 50%. Purchased product costs were higher in 2003 primarily due to:

 

•                  The Pinnacle Acquisition added $14.4 million.

•                  Increased natural gas costs offset volume decreases in Appalachia adding $21.8 million in purchased product costs.

•                  Gas marketing volumes declined primarily due to reduced volumes sold decreasing purchased product costs $6.5 million.

 

Facility expenses.  Facility expenses were $9.1 million for the six months ended June 30, 2003, compared to $8.2 million for the six months ended June 30, 2002, an increase of $0.9 million, or 11%. Facility operating expenses increased primarily due to the Pinnacle Acquisition.

 

Lease operating expenses.  Lease operating expenses were $3.7 million for the six months ended June 30, 2003, compared to $2.6 million for the six months ended June 30, 2002, an increase of $1.2 million, or 45%. Lease operating expenses increased principally due to increased rental costs and workover and saltwater disposal expenses in Canada.

 

Transportation costs.  Transportation costs were $1.0 million for the six months ended June 30, 2003, compared to $0.7 million for the six months ended June 30, 2002, an increase of $0.3 million, or 36%. Transportation costs increased primarily due to increased production from our U.S. operations.

 

Production taxes.  Production taxes were $1.3 million for the six months ended June 30, 2003, compared to $0.8 million for the six months ended June 30, 2002, an increase of $0.6 million, or 42%. Production taxes increased principally due to increased natural gas prices in 2003.

 

16

 

Selling, general and administrative expenses.  Selling, general and administrative expenses were $6.8 million for the six months ended June 30, 2003, compared to $5.6 million for the six months ended June 30, 2002, an increase of $1.2 million, or 22%. The increase is principally attributable to increased insurance costs and incremental costs associated with operating MarkWest Energy Partners as a public company.

 

Depreciation and depletion. Depreciation and depletion were $11.1 million for the six months ended June 30, 2003, compared to $10.1 million, for the six months ended June 30, 2002, an increase of $1.0 million, or 10%. Depreciation and depletion increased due to the Pinnacle Acquisition and a mid-year revision of our Canadian reserves.

 

Interest expense.  Interest expense was $3.1 million for both the six months ended June 30, 2003, compared to $2.2 million for the six months ended June 30, 2002, an increase of $0.9 million, or 35%. The settlement of interest rate swaps increased interest expense $0.6 million.

 

Write-down of deferred financing costs. We wrote off $3.0 million in deferred financing costs in 2002 as a result of amending our credit facility twice.

 

Minority interest in net income of consolidated subsidiary. This represents the minority interest (i.e., non-MarkWest Hydrocarbon) ownership in the net income of MarkWest Energy Partners, which completed its initial public offering in May 2002.

 

Cumulative effect of change in accounting for asset retirement obligations. We adopted SFAS No. 143, Asset Retirement Obligations, in the second quarter of 2003.

 

Liquidity and Capital Resources

 

MarkWest Hydrocarbon’s primary sources of liquidity are cash flow generated from operations and borrowings under our credit facility. From time to time, our sources of funds are supplemented with proceeds from sales of assets and operating leases used to finance support equipment. In 2002, we supplemented these sources through the IPO of MarkWest Energy Partners (net proceeds of $43 million, which was primarily used to pay down our debt), and the sale of 500,000 subordinated units we owned in MarkWest Energy Partners (net proceeds of $8 million).

 

MarkWest Hydrocarbon’s cash flow generated from operations is subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flow is enhanced in periods when the prices received for NGLs are high relative to the price of natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia, and is reduced in periods when the prices received for NGLs are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the 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, when natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer “whole” can result in operating losses.

 

Toward the end of the first quarter of 2003, natural gas prices began to be unusually high compared to NGL prices. This trend is forecast to continue through at least the end of 2003.  This unusual disparity in prices has reduced our internally generated cash flows.

 

To combat the reduction in cash flows and otherwise bolster our liquidity, we sold the majority of our San Juan Basin oil and gas properties on June 30, 2003, to XTO Energy Inc. for approximately $49.8 million, net of anticipated transaction costs and closing adjustments.  We expect to close on the remaining properties, valued at approximately $6.1 million, upon the receipt of necessary consents, in the near future.  We recognized a net pretax gain of approximately $19.7 million on the sale completed June 30, 2003.  The proceeds from the sale were used to repay debt outstanding under our existing credit facility in the amount of approximately $42.6 million.  The remaining proceeds will be used for general corporate purposes.

 

17

 

Almost all of our capital expenditures are discretionary.  We continue to manage our future capital expenditures to match available cash flows from operations. As of June 30, 2003, MarkWest Hydrocarbon has borrowed $24.8 million of the approximate $26.8 million available credit under our credit facility. As of July 1, 2003, we paid down an additional $11.4 million on our credit facility.

 

For MarkWest Energy Partners, future acquisitions or projects are expected to be financed through a combination of debt and issuance of additional units, as is common practice with master limited partnerships. The March 2003 Pinnacle acquisition was financed under MarkWest Energy Partners’ credit facility, which was expanded by $15 million on March 28, 2003. Additionally, MarkWest Energy Partners sold 375,000 common units in two installments at a price of $26.23 per unit in a private placement to certain accredited investors. These sales grossed $9.8 million and were completed July 10, 2003. As of June 30, 2003, MarkWest Energy Partners has borrowed $55.1 million of the $75 million available credit under its $75 million credit facility.

 

MarkWest Hydrocarbon (exclusive of MarkWest Energy Partners) forecasts a baseline capital budget of $11.4 million for 2003, almost all of which is for discretionary exploration and production projects. The capital budget may change contingent upon a number of factors, including results of operations and cash flow and availability under our credit facility.

 

Cash Flows

 

Net cash provided by operating activities was $11.6 million and $27.9 million for the six months ended June 30, 2003 and 2002, respectively. Net cash provided by operating activities decreased during the first six months of 2003 primarily due to losses from our keep-whole contract based business.

 

Net cash used in investing activities was $2.5 million and $15.9 million for the six months ended June 30, 2003 and 2002, respectively. Net cash used in investing activities was lower in 2003 due to the proceeds from the sale of our San Juan Basin properties, net of the purchase of the Pinnacle Acquisition.

 

Net cash provided by financing activities was $15.7 million during the first six months of 2003. Net cash used in financing activities was $13.1 million during the first six months of 2002.  In 2003, we had net borrowings, primarily due to the financing of the Pinnacle Acquisition. Additionally, MarkWest Energy Partners, our consolidated subsidiary, raised capital via a private placement of 375,000 of its common units. During 2002, we completed our seasonal conversion of inventories to cash, which we used to pay down long-term debt.

 

Item 3.   Quantitative and Qualitative Disclosures about Market Risk

 

Commodity Price Risk

 

Overview

 

Our business both produces products—natural gas and NGLs—and provides services—gathering, processing, transportation and marketing of natural gas and the transportation, fractionation and storage and marketing of NGLs. Our products are commodities that subject us to price risk. Commodity prices are often subject to material changes in response to relatively minor changes in supply and demand, general economic conditions and other market conditions over which we have no control, like the weather.

 

Our primary risk management objective is to manage our price risk, thereby reducing volatility in our cash flows. Our hedging approach uses a statistical method that analyzes momentum and average pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. Hedging levels may increase with capital commitments and debt levels and when above-average margins exist. We maintain a committee, including members of senior management, which oversees all hedging activity.

 

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

 

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We enter OTC swaps with counterparties that are primarily financial institutions. We use standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.

 

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) sales volumes may be less than expected requiring market purchases to meet commitments, (ii) our OTC counterparties could fail to purchase or deliver the contracted quantities of natural gas, NGL, or crude oil or otherwise fail to perform, and (iii) when the trading relationship between crude oil and NGL products is outside historical levels. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we may be similarly insulated against decreases in such prices.

 

Types of Price Risk

 

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

 

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

 

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

 

Our fully consolidated subsidiary, MarkWest Energy Partners, is also subject to NGL price risk stemming from its percent-of-proceeds contracts in Appalachia and Michigan and natural gas price risk from the Pinnacle Acquisition. MarkWest Energy Partners gathers and transports natural gas for producers behind its gathering systems in Texas and four surrounding states, many under percent-of-proceeds or percent-of-index contracts.

 

Basis Risk

 

To the extent our natural gas production equals our keep-whole requirements for purchasing natural gas in Appalachia and there are no material differences in net prices, our commodity price risk is mitigated.

 

However, we are exposed to basis risk. Our basis risk for natural gas stems from the geographic price differentials between our exploration and production (“E&P”) sales location (Alberta, Canada) and hedging contract delivery location (NYMEX) and our marketing purchase location (Appalachia) and NYMEX.  At times, we hedge our basis risk for natural gas.

 

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As of June 30, 2003, our natural gas basis hedges were as follows:

 

		Table I Hedged Natural Gas Basis
		Year Ending December 31, 2003
MMBtu		984,000
$/MMBtu		$	(0.42	)

 

We are generally unable to hedge our basis risk for NGL products. We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic basis risk because there are no readily available products or markets. Second, NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is highly correlated with certain NGL products.

 

Natural Gas Price Risk

 

Generally, we are an overall net consumer of natural gas as our keep-whole contractual requirements for purchasing natural gas in Appalachia currently exceed our natural gas production. Until such time this relationship reverses and we become a net producer of natural gas, our E&P hedges are generally limited to either (i) obtaining futures prices that our models suggest are optimal, (ii) realizing the economics of a transaction, like our 2001 Canadian E&P acquisition, or (iii) mitigating our basis risk as described above. Generally, we execute our strategy by either entering into fixed-for-float swaps or utilizing costless collars.

 

As of June 30, 2003, we have hedged our Canadian natural gas volumes and prices as follows:

 

		Table II Hedged Natural Gas Sales
		Year Ending December 31,
		2003			2004			2005
MMBtu		1,521,000			2,743,000			—
$/MMBtu		$	3.45		$	3.37		$	—

 

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Regarding our natural gas price risk from the Pinnacle Acquisition, MarkWest Energy Partners enters into fixed-for-float swaps or buys puts thereby establishing a floor sales price. As of June 30, 2003, MarkWest Energy Partners hedged its Pinnacle natural gas price risk via swaps as follows:

 

		Table III Hedged Natural Gas Sales
		Year Ending December 31,
		2003			2004			2005
MMBtu		92,000			183,000			182,500
$/MMBtu		$	5.09		$	4.57		$	4.26

 

As of June 30, 2003, MarkWest Energy Partners hedged its Pinnacle natural gas price risk via puts as follows:

 

		Table IV Hedged Natural Gas Sales
		Year Ending December 31,
		2003			2004			2005
MMBtu		184,000			366,000			—
Floor strike price ($/MMBtu)		$	4.50		$	4.00		$	—

 

NGL Product Price Risk

 

We hedge our NGL product sales by selling forward propane or crude oil. As of June 30, 2003, we have hedged NGL product sales, primarily in Appalachia, as follows:

 

		Table V Hedged Sales Price for NGL Products
		Year Ending December 31,
		2003			2004
MarkWest Hydrocarbon, Inc.
NGL Volumes Hedges Using Crude Oil
NGL gallons		48,612,000			13,113,000
NGL sales prices per gallon		$	0.44		$	0.51
MarkWest Energy Partners, L.P.
NGL Volumes Hedged Using Crude Oil
NGL gallons		1,865,000			—
NGL sales price per gallon		$	0.46		—
NGL Volumes Hedged Using Propane
NGL gallons		630,000			—
NGL sales price per gallon		$	0.41		—
Total NGL Volumes Hedged
NGL gallons		2,495,000			—
NGL sales price per gallon		$	0.44		—

 

Under Table V, all projected margins or prices on open positions assume that both (a) the basis differentials between our sales location and the hedging contract’s specified location and (b) the correlation between crude oil and NGL products, are consistent with historical averages.

 

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

 

To the extent our Appalachian natural gas purchase requirements exceed our E&P natural gas production, we are simultaneously subject to NGL price risk on the sales side and natural gas price risk on the purchase side within our GPM business. Consequently, we may hedge our Appalachian processing margin (defined as revenues less purchased product costs) by simultaneously selling propane or crude oil while purchasing natural gas.  However, as of June 30, 2003, we had no such hedges in place.

 

Interest Rate Risk

 

MarkWest Hydrocarbon, Inc.

 

We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. As of June 30, 2003, we were not a party to any financial instruments to manage this risk.

 

MarkWest Energy Partners, L.P.

 

MarkWest Energy Partners, our consolidated subsidiary, is exposed to changes in interest rates, primarily as a result of its long-term debt under its credit facility with floating interest rates.  MarkWest Energy Partners may make use of interest rate swap agreements expiring May 19, 2005 to adjust the ratio of fixed and floating rates in the debt portfolio.  As of June 30, 2002, MarkWest Energy Partners is a party to contracts to fix interest rates on $8.0 million of our debt at 3.84% compared to floating LIBOR, plus an applicable margin.

 

Item 4. Controls and Procedures

 

Pursuant to the requirements of the Securities and Exchange Commission, we maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our President and Chief Executive Officer and our Senior Vice President Finance, Chief Financial Officer and Secretary (whom we refer to in this periodic report as our Certifying Officers), as appropriate, to allow timely decisions regarding required disclosure.

 

In accordance with Rule 13a-15(b) under the Exchange Act, our management evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2003. Based upon that evaluation, our Certifying Officers concluded that, as of June 30, 2003, our disclosure controls and procedures were effective in all respects except in alerting management that certain hedging transactions completed prior to February 2002 by MarkWest Resources, Inc., our wholly owned subsidiary that we refer to as Resources, were required to be reported by us as related party transactions in our periodic reports filed with the Commission.

 

Through our ownership of Resources, we held until June 30, 2003 various undivided interests ranging from 25% to 51% in several exploration and production assets in which MAK-J Energy Partners Ltd., or MAK-J, also owned an undivided interest. MAK-J’s general partner is a corporation owned and controlled by our President and Chief Executive Officer. Because these arrangements involved a related party, the joint property acquisitions and joint operating agreements between Resources and MAK-J regarding the exploration and production assets were reviewed and approved by all of the independent members of our Board of Directors. The joint operating agreements provided that the revenues generated from and costs associated with these jointly owned and operated properties were shared pro rata in accordance with each party’s respective undivided ownership interest in such properties. Such agreements also provided that Resources had the discretion to enter into hedging transactions in respect of the properties.

 

Between August 1999 and February 2002, Resources, under the oversight of our risk management committee (which includes members of our senior management, but excludes our President and Chief Executive Officer), entered into hedging transactions with respect to these exploration and production assets on its own behalf, and on behalf of MAK-J, in accordance with the joint operating agreements.

 

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With respect to many of these hedging transactions, MAK-J was not a party to the hedge agreement. At the time of settlement of these hedging transactions, however, MAK-J would reimburse Resources for its pro rata share of any losses associated with any such hedge, and Resources would pay MAK-J its pro rata share of any profits associated with any such hedge, in each instance based upon their respective ownership interests in the assets to which the hedge related. These reimbursements and payments were made between the parties in the same manner as other joint interest billing costs and profits were allocated under the relevant operating agreements. While the joint operating agreements defined the parties rights and obligations with respect to hedging transactions generally, each individual hedging arrangement between Resources and MAK-J was not documented. Additionally, the risk management committee, while aware that both Resources and MAK-J hedged exploration and production assets with respect to which they had undivided ownership interests, was not asked formally to approve the portion of each hedge that was for the account of MAK-J.

 

The failure of Resources to fully communicate to our appropriate SEC reporting and accounting personnel that Resources was entering into hedge agreements as agent for MAK-J resulted in our failure to properly disclose those related party transactions in our periodic reports filed with the Commission. It also resulted in our failure, since January 2001, when Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” was adopted, to properly record in our financial statements the mark to market adjustment related to the portion of the hedging transactions entered into on behalf of MAK-J quarterly through earnings.

 

Our omission of the MAK-J mark to market adjustments each quarter did not, however, have any material financial impact in our consolidated financial statements for those periods.  Had we properly recorded such third party MAK-J adjustments, we would also have properly recorded an offsetting gain or loss, as applicable, on the hedge agreements between Resources and MAK-J.  Because Resources was acting as agent for MAK-J in respect of the hedging transactions, the gains and losses on the third party derivative hedging transactions and the derivative hedging transactions between Resources and MAK-J would qualify for net reporting on our consolidated statement of operations for all applicable periods. Specifically, the financial statement impact would have been to record in each period the mark to market adjustment on the third party contract as a derivative asset or liability with a corresponding offset to a payable to or receivable from MAK-J. Management of Resources has concluded that these adjustments to the previously issued consolidated financial statements are not material for restatement.

 

This deficiency in our disclosure controls and procedures was discovered during our internal due diligence process conducted in connection with our previously announced sale of our San Juan Basin oil and gas properties to XTO Energy Inc. in late June 2003. Once the deficiency was discovered and communicated to our audit committee, our audit committee retained PricewaterhouseCoopers LLP to assist it in assessing if there were any material deficiencies in our disclosure controls and procedures. Our audit committee also retained an outside law firm to conduct an investigation into the circumstances giving rise to the omission. Following the performance of its review, PricewaterhouseCoopers provided a report to the audit committee setting forth its observations and recommendations, which are summarized below.

 

Notwithstanding that the mark to market entry omission did not have a material financial impact on our financial statements, our independent auditor reported to us that these weaknesses in our internal control over financial reporting constituted material weakness under Statement on Auditing Standards No. 60. A material weakness under SAS No. 60 is a reportable condition in which the design or operation of one or more of the internal control components does not reduce to a relatively low level the risk that misstatements caused by error or fraud in amounts that would be material in relation to the financial statements being audited may occur and not be detected within a timely period by employees in the normal course of performing their assigned functions. To reduce the likelihood that our hedging activity and related party disclosures may be misreported in the future, our independent auditor recommended that we take, among others, the following measures:

 

•                  Establish a specific written policy regarding related party hedging transactions;

•                  Involve to a greater degree accounting personnel in all hedging transactions;

•                  Require by policy that all hedging transactions be appropriately documented; and

•                  Strengthen our procedures used to identify related party transactions to ensure prior approval of all such transactions by our board of directors.

 

Our audit committee decided to address the hedging disclosure omission by directing us not to enter into any future related party hedging transactions and by implementing enhanced procedures designed to identify any related party transaction that might require disclosure.

 

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Because these deficiencies were identified after the completion of our second fiscal quarter, there were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Furthermore, because our audit committee has determined it to be in our best interests and in the best interests of our stockholders to prohibit us and our subsidiaries from engaging in any future related party hedging transactions, and because all of our and Resources’ other hedging activities were properly recorded and disclosed, the audit committee determined that it did not need to change our internal control over financial reporting in response to this matter in this third or any future quarter, other than to proscribe our engaging in related party hedging transactions in the future.

 

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PART II  OTHER INFORMATION

 

Item 1.  Legal Proceedings

 

Reference is made to Note 8 to the Consolidated Financial Statements included earlier in this Form 10-Q.

 

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

 

At the Annual Meeting of Stockholders held on May 15, 2003, the following proposals were adopted by the margins indicated:

 

1.               To elect three Class III directors to hold office for a three-year term expiring at the Annual Meeting of Stockholders occurring in the year 2006 or until the election and qualification of their respective successors.

 

		Number of Shares
		For		Withheld
Arthur J. Denney		8,104,370		27,307
Donald C. Heppermann		8,109,388		22,289
Karen L. Rogers		8,117,327		14,350

 

2.               To ratify the selection of PricewaterhouseCoopers LLP as our independent accountants for the fiscal year ending December 31, 2003.

 

		Number of Shares
For		8,129,177
Against		2,500
Abstain		0

 

Item 6.  Exhibits and Reports on Form 8-K

 

(a)                                  Exhibits

 

11*                             Statement regarding computation of earnings per share.

 

31.1*                    Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act.

 

31.2*                    Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act.

 

32.1*                    Certification of 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 Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

* Filed herewith.

 

(b)                                 Reports on Form 8-K

 

A report on Form 8-K was filed with the SEC on April 14, 2003, announcing that MarkWest Energy Partners completed its acquisition of Pinnacle Natural Gas Company and certain affiliates on March 28, 2003, amended by Form 8-K/A filed with the SEC on June 11, 2003, which included the unaudited financial statements of PNG Corporation and subsidiaries.

 

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A report on Form 8-K was filed with the SEC on May 14, 2003, concerning MarkWest Hydrocarbon’s first quarter 2003 earnings release dated May 14, 2003.

 

A report on Form 8-K was filed with the SEC on June 12, 2003, announcing MarkWest Hydrocarbon had entered into a definitive Purchase and Sale Agreement with XTO Energy Inc. relating to the sale of MarkWest Hydrocarbon, Inc.’s San Juan Basin oil and gas properties.

 

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SIGNATURE

 

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

 

 

			MarkWest Hydrocarbon, Inc.
			(Registrant)
Date:  August 14, 2003		By:	/s/ Donald C. Heppermann
			Donald C. Heppermann
			Senior Vice President Finance,
			Chief Financial Officer and Secretary

 

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