UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
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 1-31239

 

 

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 by Rule 12b-2 of the Act).

Yes    ý     No    o

 

The number of the registrant’s Common Units outstanding at July 31, 2003, was 2,790,000 common units and 3,000,000 subordinated units.

 

 

PART I—FINANCIAL INFORMATION
Item 1.   Financial Statements
	Consolidated and Combined Balance Sheets at June 30, 2003 and December 31, 2002
	Consolidated and Combined Statements of Operations for the Three Months Ended June 30, 2003 and 2002
	Consolidated and Combined Statements of Operations for the Six Months Ended June 30, 2003 and 2002
	Consolidated and Combined Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002
	Consolidated and Combined Statements of Changes in Capital for the Six Months Ended June 30, 2003
	Notes to the Consolidated and Combined 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 6.   Exhibits and Reports on Form 8-K
SIGNATURE

 

Glossary of Terms

 

Bcf/d	billion cubic feet of natural gas per day
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
NGLs	natural gas liquids, such as propane, butanes and natural gasoline

 

 

PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements

 

MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED BALANCE SHEETS
(UNAUDITED)

 

		June 30, 2003			December 31, 2002
		(in thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	7,920		$	2,776
Receivables		7,550			976
Receivables from affiliate		1,919			2,847
Inventories		114			130
Other assets		528			336
Total current assets		18,031			7,065
Property, plant and equipment:
Gas gathering equipment		34,398			34,398
Gas processing plants		47,427			47,403
Pipelines		38,056			—
Fractionation and storage equipment		22,076			22,076
NGL transportation equipment		4,415			4,402
Land, building and other equipment		3,088			3,021
Construction in progress		736			348
		150,196			111,648
Less: Accumulated depreciation		(35,004		)	(31,824		)
Total property, plant and equipment, net		115,192			79,824
Deferred financing costs		1,141			820
Total assets		$	134,364		$	87,709
LIABILITIES AND CAPITAL
Current liabilities:
Accounts payable		$	6,251		$	1,199
Payables to affiliate		893			723
Accrued liabilities		5,712			2,880
Risk management liability		567			501
Total current liabilities		13,423			5,303
Long-term debt		55,100			21,400
Risk management liability		310			143
Commitments and contingencies
Capital:
Partners’ capital		66,441			61,574
Accumulated other comprehensive income (loss), net of tax		(910		)	(711		)
Total capital		65,531			60,863
Total liabilities and capital		$	134,364		$	87,709

 

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

 

1

 

MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(UNAUDITED)

 

		Three Months Ended June 30, 2003 (Partnership)			Period From Commencement of Operations (May 24, 2002) Through June 30, 2002 (Partnership)			Period From April 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
		(in thousands, except per unit amounts)
Revenues:
Sales to affiliate		$	10,082		$	3,875		$	—
Sales to unaffiliated parties		19,554			985			9,603
Total revenues		29,636			4,860			9,603
Operating expenses:
Purchased gas costs		18,423			1,533			6,923
Facility expenses		5,167			1,343			1,926
Selling, general and administrative expenses		1,678			529			843
Depreciation		1,860			515			714
Total operating expenses		27,128			3,920			10,406
Income (loss) from operations		2,508			940			(803		)
Other income and (expenses):
Interest expense, net		(984		)	(136		)	(161		)
Miscellaneous income		14			6			—
Income (loss) before income taxes		1,538			810			(964		)
Provision (benefit) for income taxes:
Current due to (from) parent		—			—			(1,315		)
Deferred		—			—			945
Provision (benefit) for income taxes		—			—			(370		)
Net income (loss)		$	1,538		$	810		$	(594	)
General partner’s interest in net income		$	31		$	16
Limited partners’ interest in net income		$	1,507		$	794
Net income per limited partner unit		$	0.28		$	0.15
Weighted average units outstanding		5,428			5,415

 

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

 

2

 

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

		Six Months Ended June 30, 2003 (Partnership)			Period From Commencement of Operations (May 24, 2002) Through June 30, 2002 (Partnership)			Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
		(in thousands, except per unit amounts)
Revenues:
Sales to affiliates		$	23,476		$	3,875		$	—
Sales to unaffiliated parties		23,853			985			37,043
Total revenues		47,329			4,860			37,043
Operating expenses:
Purchased gas costs		26,815			1,533			26,598
Facility expenses		9,504			1,343			5,705
Selling, general and administrative expenses		2,931			529			2,206
Depreciation		3,205			515			1,916
Total operating expenses		42,455			3,920			36,425
Income from operations		4,874			940			618
Other income and (expenses):
Interest expense, net		(1,745		)	(136		)	(461		)
Miscellaneous income		34			6			—
Income before income taxes		3,163			810			157
Provision (benefit) for income taxes:
Current due to (from) parent		—			—			(1,535		)
Deferred		—			—			1,596
Provision for income taxes		—			—			61
Net income		$	3,163		$	810		$	96
General partner’s interest in net income		$	63		$	16
Limited partners’ interest in net income		$	3,100		$	794
Net income per limited partner unit		$	0.57		$	0.15
Weighted average units outstanding		5,422			5,415

 

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

 

3

 

MARKWEST ENERGY PARTNERS, L.P.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(UNAUDITED)

 

		Six Months Ended June 30, 2003 (Partnership)			Period From Commencement of Operations (May 24, 2002) Through June 30, 2002 (Partnership)			Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
		(in thousands)
Cash flows from operating activities:
Net income		$	3,163		$	810		$	96
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		3,205			515			1,916
Amortization of deferred financing costs includedinterest expense		438			—			—
Non-cash compensation expense		400			—			—
Deferred income taxes		—			—			1,596
Other		9			37			(252		)
Changes in operating assets and liabilities:
(Increase) decrease in receivables		2,511			(4,852		)	3,765
(Increase) decrease in inventories		16			(104		)	2,449
(Increase) decrease in prepaid replacement natural gas and other assets		(114		)	(79		)	5,253
Increase (decrease) in accounts payable and accrued liabilities		250			3,652			7,770
Increase in long-term replacement natural gas payable		—			—			3,090
Net cash flow provided by (used in) operating activities		9,878			(21		)	25,683
Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired		(38,238		)	—			—
Capital expenditures		(1,144		)	(57		)	(498		)
Proceeds from sale of assets		3			—			—
Net cash used in investing activities		(39,379		)	(57		)	(498		)
Cash flows from financing activities:
Proceeds from initial public offering, net		—			43,649			—
Proceeds from private placement of common units, net		7,807			—			—
Proceeds from long-term debt		51,000			21,400			—
Repayment of long-term debt		(17,300		)	—			—
Distributions to unitholders		(6,103		)	—			—
Net advances from (distributions to) parent		—			—			(24,218		)
Debt due to (from) parent		—			—			(967		)
Payments for debt issuance costs		(759		)	(1,018		)	—
Distribution to MarkWest Hydrocarbon		—			(63,476		)	—
Net cash provided by (used in) financing activities		34,645			555			(25,185		)
Net increase in cash		5,144			477			—
Cash and cash equivalents at beginning of period		2,776			—			—
Cash and cash equivalents at end of period		$	7,920		$	477		$	—

 

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

 

4

 

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN CAPITAL

(UNAUDITED)

 

															Accumulated Other Comprehensive Income (Loss)			Total
		PARTNERS’ CAPITAL
		Limited Partners
		Common					Subordinated					General Partner
		Units		$			$		Units			$			$
		(in thousands)
Balance at December 31, 2002		2,415		$	43,858		3,000		$	17,357		$	359		$	(711	)	$	60,863
Private placement of common units, net of transaction costs		300		7,807			—		—			—			—			7,807
Distributions to partners		—		(2,657		)	—		(3,300		)	(146		)	—			(6,103		)
Net income		—		1,384			—		1,716			63			—			3,163
Change in fair value of derivatives		—		—			—		—			—			(199		)	(199		)
Balance at June 30, 2003		2,715		$	50,392		3,000		$	15,773		$	276		$	(910	)	$	65,531

 

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

 

5

 

MARKWEST ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

1.              Organization

 

MarkWest Energy Partners, L.P. (the “Partnership”, “we” or “us”), a Delaware limited partnership, was formed in January 2002 to own and operate substantially all of the assets, liabilities and operations of MarkWest Hydrocarbon, Inc.’s (“MarkWest Hydrocarbon”) midstream business (the “MarkWest Hydrocarbon Midstream Business” or the “Midstream Business”). We are engaged in the business of gathering, processing and transporting natural gas and the transportation, fractionation and storage of NGL products.

 

2.              Basis of Presentation

 

The accompanying unaudited consolidated and combined financial statements include the accounts of MarkWest Energy Partners, L.P. and its wholly owned subsidiaries. The financial statements have been prepared in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim financial reporting.  These financial statements involve the use of estimates and judgments where appropriate. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s and the Midstream Business’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. You should read these consolidated and combined financial statements along with the audited financial statements and notes thereto included in our December 31, 2002 Annual Report on Form 10-K.  Results for the three and six months ended June 30, 2003, are not necessarily indicative of results for the full year 2003.

 

3.              Pinnacle Acquisition

 

On March 28, 2003, we 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 the Partnership 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

 

6

 

Pro Forma Results of Operations (Unaudited)

 

The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, 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 indicative of future results.

 

		Six Months Ended June 30, 2003			Period From Commencement of Operations (May 24, 2002) Through June 30, 2002 (Partnership)			Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
		(in thousands, except per unit data)
Revenue		$	65,867		$	9,523		$	51,687
Net income		$	3,878		$	547		$	15
Basic net income per limited partner unit(1)		$	0.70		$	0.10		N/A
Diluted net income per limited partner unit(1)		$	0.70		$	0.10		N/A

 

N/A- Not applicable

(1)          The MarkWest Hydrocarbon Midstream Business did not issue any units. Consequently, no earnings per limited partner unit information is a available.

 

4.              Private Placement

 

The Partnership 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. The Partnership’s general partner paid its pro rata contribution in July 2003 after the second installment was completed. We used the proceeds to pay down debt under our credit facility.

 

5.              Distribution to Unitholders

 

On May 15, 2003, we paid our cash distribution of $0.58 per unit for the quarterly period ended March 31, 2003. The distribution was declared on April 17, 2003, payable to unitholders of record as of May 5, 2003.

 

On July 11, 2003, we declared our cash distribution of $0.58 per unit for the quarterly period ended June 30, 2003. The distribution will be paid on August 14, 2003, to unitholders of record as of August 4, 2003.

 

6.              Net Income Per Limited Partner Unit

 

Basic and diluted net income per unit is determined by dividing net income, after deducting the general partner’s 2% interest, by the weighted average number of outstanding common units and subordinated units.

 

7.              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 unit-based and stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We have a variable plan and certain employees of MarkWest Hydrocarbon who perform services for MarkWest Energy Partners receive stock-based compensation awards from MarkWest Hydrocarbon. We account for these plans using variable and fixed accounting as appropriate. 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

 

7

 

corresponding quarter and is amortized into earnings over the period of service. For the six months ended June 30, 2003, we recognized $0.4 million of compensation expense for the variable plan. MarkWest Hydrocarbon 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.

 

Had compensation cost for those employees principally supporting the Partnership who participated in MarkWest Hydrocarbon’s stock-based compensation plan been determined based on the fair value at the grant dates under the plan consistent with the method prescribed by SFAS No. 123, our net income and net income per limited partner unit would have been affected as follows:

 

8

 

		Three Months Ended June 30, 2003 (Partnership)			Period From Commencement of Operation (May 24, 2002) Through June 30, 2002 (Partnership)			Period from April 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
		(in thousands, except per unit data)
Net income (loss) as reported		$	1,538		$	810		$	(594	)
Deduct:  Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(47		)	(19		)	(27		)
Pro forma net income (loss)		$	1,491		$	791		$	(567	)
Net income per limited partner unit: (1)
Basic—as reported		$	0.28		$	0.15		N/A
Basic—pro forma		$	0.27		$	0.15		N/A
Diluted—as reported		$	0.28		$	0.15		N/A
Diluted—pro forma		$	0.27		$	0.15		N/A

 

		Six Months Ended June 30, 2003 (Partnership)			Period From Commencement of Operation (May 24, 2002) Through June 30, 2002 (Partnership)			Period from January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
		(in thousands, except per unit data)
Net income, as reported		$	3,163		$	810		$	96
Deduct:  Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(92		)	(19		)	(72		)
Pro forma net income		$	3,071		$	791		$	24
Net income per limited partner unit: (1)
Basic—as reported		$	0.57		$	0.15		N/A
Basic—pro forma		$	0.57		$	0.15		N/A
Diluted—as reported		$	0.57		$	0.15		N/A
Diluted—pro forma		$	0.57		$	0.15		N/A

 

N/A—Not applicable

(1)          The MarkWest Hydrocarbon Midstream Business did not issue any units. Consequently, no earnings per limited partner unit information is available.

 

8.              Subsequent Events

 

On July 31, 2003, the Partnership, through its wholly owned subsidiary, MarkWest Pinnacle, L.P., entered into a Purchase and Sale Agreement to purchase a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12 million. The transaction is expected to close on September 1, 2003, and it will be financed through borrowings under our existing credit facility.

 

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

 

9

 

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

 

Forward-Looking Statements

 

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

 

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

 

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

 

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

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

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

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

•                  Prices of NGL products and crude oil, including the effectiveness of any hedging activities, and indirectly by natural gas prices.

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

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

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

•                  Our ability to integrate the Pinnacle Acquisition.

 

Many of such factors are beyond our ability to control or predict. Investors are cautioned not to put undue reliance on forward-looking statements.

 

Results of Operations

 

Overview

 

We are a Delaware limited partnership formed by MarkWest Hydrocarbon to acquire most of the assets, liabilities and operations of the Midstream Business. We are engaged in the gathering, processing and transportation of natural gas and the transportation, fractionation, and storage of NGL products. We are the largest processor of natural gas in the northeastern United States, processing gas from the Appalachian basin, one of the country’s oldest natural gas producing regions, and from Michigan. Additionally, since March 28, 2003, through our merger with the Pinnacle companies (see further information below), we gather and transport natural gas in the western part of Texas.

 

The financial statements of MarkWest Energy Partners, L.P., reflect historical cost-basis accounts of the Midstream Business for periods prior to May 24, 2002, the closing date of our IPO (see Note 1 of the Notes to Consolidated and Combined Financial Statements appearing earlier in this Form 10-Q) and include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead and the results of contracts in force at that time. Beginning on May 24, 2002, the consolidated and combined financial statements reflect the financial statements of the Partnership and its subsidiaries, including the results of contracts entered into on May 24, 2002.

 

10

 

The Midstream Business’s financial statements differ substantially from our financial statements principally because of the differences in the way in which we generate revenues compared to the way in which the MarkWest Hydrocarbon Midstream Business generated revenues. Historically, the Midstream Business primarily generated its revenues pursuant to:

 

•                  “Keep-whole” contracts under which Midstream Business would take title to and sell the NGLs it produced in its processing operations and would reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the redelivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas.

 

•                  “Percent-of-proceeds” contracts under which the Midstream Business would take title to the NGLs it produced in its processing operations, sell the NGLs to third parties, and pay the producer a specified percentage of the proceeds received from the sales.

 

•                  Fee-based contracts under which the Midstream Business received a fee in exchange for services – transportation, processing, or fractionation – that it provided.

 

However, currently, none of our revenues are generated pursuant to keep-whole contracts. Rather, we generate the majority of our revenues pursuant to:

 

•                  Percent-of-proceeds contracts that were acquired in connection with the Pinnacle Acquisition, under which we retain a percentage of the proceeds from the sale of natural gas and NGLs we transport, primarily in Texas, as compensation for our services. We also generate revenues in Texas from contracts pursuant to which we receive a flat monthly fee in exchange for delivering natural gas to end users.

 

•                  Contracts that we entered into with MarkWest Hydrocarbon at the closing of our IPO that provide for us to be paid a fee per unit for processing, fractionation and other services that we provide in Appalachia.

 

•                  Percent-of-proceeds contracts, which we assumed from MarkWest Hydrocarbon at the completion of our IPO, under which we retain a percentage of the NGLs that we produce in Appalachia and Michigan as compensation for processing the raw gas for producers.

 

•                  Fee-based contracts under which we receive a fee in exchange for services — transportation, processing, for fractionation – that we provide.

 

The largest of the differences between the financial statements of the Midstream Business and our financial statements is in revenues and purchased product cost. Generally, revenues and purchased product costs in the Midstream Business’s financial statements are higher because:

 

•                  The Midstream Business’s revenues included the aggregate sales price for all the NGL products produced in its operations.

 

•                  The Midstream Business’s purchased product costs included the cost of natural gas purchases needed to replace the Btu content of the NGLs extracted in its processing operations and the percentage of the proceeds from the sale of NGL products remitted to producers under percent-of-proceeds contracts.

 

In contrast, our revenues and purchased product costs, for the most part, do not include these items. Instead,

 

•                  Our revenues include just the fees we receive for the provision of gathering, processing, transportation, fractionation and storage services and the aggregate proceeds from natural gas and NGL sales we receive under our percent-of-proceeds and percent-of-index contracts.

 

11

 

•                  Our purchased product costs primarily consists of the percentage of proceeds from the sale of natural gas and NGL products remitted to producers under our percent-of-proceeds and percent- of-index contracts.

 

Accordingly, whereas the Midstream Business’s results of operations depended on the volumes of NGL products sold and the difference between the sale price of NGL products and the cost of replacement natural gas, our results of operations depend primarily on the volume of natural gas processed, NGLs fractionated and, to the extent of our percent-of-proceeds contracts, the market price of natural gas and NGL products. Because of these significant differences, the “Results of Operations” for the Midstream Business discussed below may be of limited use in evaluating the business conducted by us. The nature of the Midstream Business’s and our revenues and costs are presented in more extensive detail below and may help you better understand the historical results discussed herein, as well as our operating results going forward.

 

MarkWest Hydrocarbon Midstream Business

 

The Midstream Business historically generated the majority of its revenues through the sale of NGL products obtained in exchange for providing processing and fractionation services to natural gas producers.  NGL product prices, and the volume of natural gas processed and NGLs fractionated and sold, were the primary determinants of revenues. In Appalachia, the Midstream Business processed natural gas under keep-whole contracts and a contract containing both fee and percent-of-proceeds components. In Michigan, the Midstream Business processed natural gas under contracts containing both fee and percent-of-proceeds components. Under keep-whole and percent-of-proceeds contracts, the Midstream Business recorded as revenues the gross proceeds retained from the sale of NGL products produced. Gathering and processing contracts containing a fee component required producers to pay the Midstream Business a fee to gather and process their gas.

 

The Midstream Business’s purchased product costs were comprised of a keep-whole contract component and a percent-of-proceeds contract component. Under keep-whole contracts, the Midstream Business’s principal cost was the reimbursement to the natural gas producers for the energy extracted from their natural gas stream in the form of NGLs. The Midstream Business kept the producers whole on an energy basis by replacing the extracted Btu content of the NGLs with additional volumes of dry natural gas. Under percent-of-proceeds contracts, the Midstream Business’s principal cost was the percentage of the proceeds from the sale of the NGL products that was remitted to the producers.

 

The Midstream Business’s facility expenses principally consisted of costs needed to operate its facilities, including personnel costs, fuel needed to operate the plants, plant utility costs and maintenance expenses. The Midstream Business’s fuel costs were partially offset by contractual reimbursements from producers. Some operating costs, such as fuel costs, fluctuated depending on the amount of natural gas processed or NGL products fractionated and the price of natural gas.

 

The Midstream Business’s general and administrative expenses were costs allocated by MarkWest Hydrocarbon. Historically, these costs have included legal, accounting, treasury, engineering, information technology, insurance and other corporate services.

 

MarkWest Energy Partners, L.P.

 

We generate the majority of our revenues from natural gas gathering, processing and transportation and NGL transportation, fractionation and storage.

 

With the completion of the Pinnacle Acquisition on March 28, 2003, revenues are primarily generated by providing the end user with natural gas gathering and transportation services in producing areas located in Texas, New Mexico, Louisiana and Mississippi. The Pinnacle Acquisition provides us with additional customer diversification as all of the revenues generated from the Pinnacle assets are with third parties. For the three months ended June 30, 2003, the first full quarter in which the Pinnacle Acquisition’s results were included in our Statement of Operations, the Pinnacle assets generated 56% of our revenues.

 

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In Appalachia, our primary sources of revenues are our operating agreements with MarkWest Hydrocarbon.  These operating agreements include:

 

•                  A Gas Processing Agreement under which MarkWest Hydrocarbon delivers all gas gathered by Columbia Gas and delivered to MarkWest Hydrocarbon upstream of our facilities for processing at our Kenova, Boldman and Cobb plants. As payment for these services, we receive a monthly processing fee based on the natural gas volumes delivered to us.

 

•                  A Pipeline Liquids Transportation Agreement under which MarkWest Hydrocarbon delivers all of its NGLs acquired from our Kenova facility, and any of its NGLs it desires to deliver from our Boldman facility or from other sources in the Appalachian region for transportation through our pipeline facilities to our Siloam fractionation facility. As payment for these services, MarkWest Hydrocarbon pays us a monthly transportation fee based on the number of gallons transported.

 

•                  A Fractionation, Storage and Loading Agreement under which MarkWest Hydrocarbon delivers all of the mixed NGLs produced at our Kenova, Boldman or Cobb processing plants for fractionation at our Siloam fractionation facility. We unload the NGLs delivered to us, fractionate all the NGLs, lease tracking rights on our Siloam railroad siding to MarkWest Hydrocarbon, load the finished NGL products for shipment and as directed by MarkWest Hydrocarbon, store the finished NGL products in underground storage caverns. As payment for these services, MarkWest Hydrocarbon pays us a monthly fractionation fee based on the number of gallons we fractionate, an annual storage fee and a monthly fee based on the number of gallons of NGLs we unload at our Siloam facility.

 

•                  A Natural Gas Liquids Purchase Agreement under which MarkWest Hydrocarbon receives and purchases, and we deliver and sell, all of the NGL products we produce pursuant to our gas processing agreement with a third party. Under the terms of this agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This contract applies to any other NGL products we acquire. We retain a percentage of the proceeds attributable to the sale of NGL products we produce pursuant to our agreement with a third party, and remit the balance from such NGL product sale proceeds to a third party.

 

A portion of each of the above-mentioned fees is adjusted annually to reflect changes in the Producers Price Index for Oil and Gas Field Services.

 

In Michigan, we assumed the MarkWest Hydrocarbon Midstream Business’s existing contracts and gather and process natural gas directly for those third parties. We receive 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that we gather in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income we earn on quarterly Michigan pipeline throughput in excess of 10,000 Mcf/d.

 

Our principal purchased product costs are the percentage of proceeds from the sale of NGL products that we remit to a third party in Appalachia and the third-party producers in Michigan. We also pay third-party producers in Texas a percentage of index or a percentage of proceeds for the gas we gather.

 

Our plant operating expenses, similar to the Midstream Business, principally consist of those expenses needed to operate our facilities, including applicable personnel costs, fuel, plant utility costs and maintenance expenses. One difference between our plant operating expenses and those of the MarkWest Hydrocarbon Midstream Business is fuel costs. MarkWest Hydrocarbon retains the producer fuel reimbursement.

 

Our general and administrative expenses are dictated by the terms of the omnibus agreement between MarkWest Hydrocarbon and us. We reimburse MarkWest Hydrocarbon monthly for the general and administrative

 

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support it provided us in the prior month. In the first year of the agreement (ended May 23, 2003), this reimbursement did not exceed $4.9 million. This limitation excluded the cost of any third party legal, accounting or advisory services received, or the direct expenses of MarkWest Hydrocarbon and its affiliates incurred, in connection with business development opportunities evaluated on our behalf.

 

Pinnacle Acquisition

 

We completed the Pinnacle Acquisition on March 28, 2003. 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 the Partnership 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/d 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 our 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. This extended maintenance resulted in reduced fractionation and processing revenues.

 

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

 

Operating Data

 

		Three Months Ended June 30, 2003 (Partnership)		Period From Commencement of Operations (May 24, 2002) Through June 30, 2002 (Partnership)		Period From April 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
Appalachia:
Natural gas processed for a fee(1) (Mcf/d) under contracts in effect:
Beginning May 24, 2002		252,000		—		—
Prior to May 24, 2002		—		252,000		283,000
NGLs fractionated for a fee (gallons/day) under contracts in effect:
Beginning May 24, 2002		391,000		449,000		—
Prior to May 24, 2002		—		—		463,000
NGL product sales (gallons) under contracts in effect:
Beginning May 24, 2002		8,116,000		3,551,000		—
Prior to May 24, 2002		—		—		18,555,000
Texas(2):
Pipeline throughput (Mcf/d)		42,000		—		—
Michigan:
Natural gas processed for a fee (Mcf/d)		14,500		13,400		11,200
NGL product sales (gallons)		2,917,000		1,140,000		1,314,400

 

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

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

 

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Revenues.  Revenues were $29.6 million for the three months ended June 30, 2003, compared to our combined revenues of $14.5 million for the three months ended June 30, 2002, an increase of $15.2 million, or 105%. Revenues were higher in 2003 than in 2002 primarily due to the Pinnacle Acquisition, which added $16.7 million in revenues. The Pinnacle-related additions were offset by lower throughput volumes in Appalachia, a result of unexpected repairs to certain facilities, and new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our IPO. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the financial statement line item differences between the Partnership and the Midstream Business.

 

Purchased Product Costs. Purchased product costs were $18.4 million for the three months ended June 30, 2003, compared to our combined purchased product costs of $8.4 million for the three months ended June 30, 2002, an increase of $10.0 million, or 118%. Purchased product costs were higher in 2003 than in 2002 primarily due to the Pinnacle Acquisition, which added $13.8 million in purchased product costs. The Pinnacle-related additions were offset by lower throughput and sales volumes in Appalachia, a result of unexpected repairs to certain facilities, and new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the financial statement line item differences between the Partnership and the Midstream Business.

 

Facility Expenses. Facility expenses were $5.2 million for the three months ended June 30, 2003, compared to our combined facility expenses of $3.3 million for the three months ended June 30, 2002, an increase of $1.9 million, or 58%. Facility expenses increased $0.9 million due to the Pinnacle Acquisition. The remainder of the increase is attributable to higher fuel and repair costs in Appalachia and increased throughput in Michigan.

 

Selling, General and Administrative Expenses. Selling, general and administrative expenses were $1.7 million for the three months ended June 30, 2003, compared to our combined expenses of $1.4 million for the three months ended June 30, 2002, an increase of $0.3 million, or 16%.  Increased expenses are primarily attributable to the Pinnacle Acquisition.

 

Depreciation. Depreciation expense was $1.9 million for the three months ended June 30, 2003, compared to our combined depreciation expense of $1.2 million for the three months ended June 30, 2002, an increase of $0.6 million, or 51%. The increase is principally due to the Pinnacle Acquisition.

 

Interest Expense. Interest expense was $1.0 million for the three months ended June 30, 2003, compared to our combined interest expense of $0.3 million for the three months ended June 30, 2002. The increase in interest expense is primarily a result of the additional debt used to finance the Pinnacle Acquisition.

 

Income Taxes. The Partnership has not been subject to income taxes since its inception on May 24, 2002.

 

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

 

Operating Data

 

		Six Months Ended June 30, 2003 (Partnership)		Period From Commencement of Operations (May 24, 2002) Through June 30, 2002 (Partnership)		Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
Appalachia:
Natural gas processed for a fee(1) (Mcf/d) under contracts in effect:
Beginning May 24, 2002		258,000		—		—
Prior to May 24, 2002		—		252,000		274,000
NGLs fractionated for a fee (gallons/day) under contracts in effect:
Beginning May 24, 2002		418,000		449,000		—
Prior to May 24, 2002		—		—		462,000
NGL product sales (gallons) under contracts in effect:
Beginning May 24, 2002		18,199,000		3,551,000		—
Prior to May 24, 2002		—		—		75,821,000
Texas(2):
Pipeline throughput (Mcf/d)		42,000		—		—
Michigan:
Natural gas processed for a fee (Mcf/d)		14,900		13,400		11,900
NGL product sales (gallons)		5,859,000		1,140,000		3,747,000

 

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

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

 

Revenues.  Revenues were $47.3 million for the six months ended June 30, 2003, compared to our combined revenues of $41.9 million for the six months ended June 30, 2002, an increase of $5.4 million, or 13%.  Revenues were higher in 2003 than in 2002 primarily due to the Pinnacle Acquisition, which added $17.5 million in revenues. The Pinnacle-related additions were offset by lower throughput volumes in Appalachia, a result of unexpected repairs to certain facilities, and new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the financial statement line item differences between the Partnership and the Midstream Business.

 

Purchased Product Costs. Purchased product costs were $26.8 million for the six months ended June 30, 2003, compared to our combined purchased product costs of $28.1 million for the six months ended June 30, 2002, a decrease of $1.3 million, or 5%. Purchased product costs were lower in 2003 than in 2002 primarily due to lower throughput and sales volumes in Appalachia, a result of unexpected repairs to certain facilities, new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our IPO. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the financial statement line item differences between the Partnership and the Midstream Business. These decreases were partially offset by the Pinnacle Acquisition.

 

Facility Expenses. Facility expenses were $9.5 million for the six months ended June 30, 2003, compared to our combined facility expenses of $7.0 million for the six months ended June 30, 2002, an increase of $2.5 million, or 35%. The Pinnacle acquisition increased facility expenses by $1.0 million. The remainder of the increase is principally attributable to higher fuel and repair costs in Appalachia and increased throughput in Michigan.

 

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Selling, General and Administrative Expenses. Selling, general and administrative expenses were $2.9 million for the six months ended June 30, 2003, compared to our combined selling, general and administrative expenses of $2.7 million for the six months ended June 30, 2002, an increase of $0.2 million, or 7%.

 

Depreciation. Depreciation expense was $3.2 million for the six months ended June 30, 2003, compared to $2.4 million for the six months ended June 30, 2002, an increase of $0.8 million, or 32%. Depreciation expense increased primarily due to the Pinnacle Acquisition.

 

Interest Expense. Interest expense was $1.7 million for the six months ended June 30, 2003, compared to $0.6 million for the six months ended June 30, 2002. Interest expense increased due to additional debt used for the financing of the Pinnacle Acquisition.

 

Income Taxes. The Partnership has not been subject to income taxes since its inception on May 24, 2002.

 

Seasonality

 

A portion of the Midstream Business’s revenues and, as a result, its gross margins, were dependent upon the sales prices of NGL products, particularly propane, which fluctuate with winter weather conditions, and other supply and demand determinants. The strongest demand for propane, which increases sales volumes, and the highest propane sales margins generally occur during the winter heating season.  As a result, the Midstream Business recognized a substantial portion of its annual income during the first and fourth quarters of the year.

 

With respect to our percent-of-proceeds and percent-of-index contracts, which account for approximately 25% of our gross margin (revenue less purchased product costs) for the six months ended June 30, 2003, we are dependent upon the sales prices of natural gas and NGL products, particularly propane, which fluctuates with the winter weather conditions, and other supply and demand determinants.

 

Liquidity and Capital Resources

 

We believe that cash generated from operations and funds available under our credit facility will be sufficient to meet both our short-term and long-term working capital requirements and anticipated capital expenditures. Over a two-week period ended July 10, 2003, we issued an additional 375,000 common units in a private placement to certain accredited investors raising approximately $9.7 million after transaction costs.  We have the ability to issue additional common units to raise capital. The potential $12.0 million Power-Tex pipeline acquisition, expected to close September 1, 2003, will be financed through borrowings under our credit facility. Our ability to fund additional acquisitions will likely require the issuance of additional common units, the expansion of our credit facility, or the issuance of additional debt instruments.

 

Our ability to pay distributions to our unitholders and to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

 

Our primary customer is MarkWest Hydrocarbon. For the three months ended June 30, 2003, the first full quarter in which the Pinnacle Acquisition’s results were included in our Statement of Operations, MarkWest Hydrocarbon accounted for 55% of our gross margin (defined as revenue less purchased product cost). Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors, and the like—have the potential to impact, both positively and negatively, our liquidity.

 

Sustaining capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives, are estimated to approximate $0.3 million for the remainder of 2003. Additionally, our budget for Pinnacle pipeline connections and other system improvements, excluding the potential Power-Tex pipeline acquisition, for the remainder of 2003 is $1.2 million. Under certain circumstances, the party from which we acquired the Pinnacle assets has the right to require MarkWest Energy Partners to purchase an additional lateral pipeline for up to $2.5

 

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million.

 

Cash Flows.  Net cash provided by operating activities was $9.9 million for the six months ended June 30, 2003, compared to our combined cash flow $25.7 million for the six months ended June 30, 2002.  The difference in net cash provided by operating activities is attributable to the inherent differences in the businesses and contracts of the Partnership and the Midstream Business. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the differences between the Partnership and the Midstream Business.

 

Net cash used in investing activities was $39.4 million for the six months ended June 30, 2003, compared to our combined cash flow of $0.6 million for the six months ended June 30, 2002. The increase was primarily caused by the acquisition of the Pinnacle companies on March 28, 2003.

 

Net cash provided by financing activities was $34.6 million for the six months ended June 30, 2003. Our combined net cash used in investing activities was $24.6 million for the six months ended June 30, 2002. Net cash provided by financing activities for 2003 was caused by borrowings used to finance the Pinnacle Acquisition and proceeds from the private placement of common units. Financing activities through June 30, 2002, primarily represent repayments to MarkWest Hydrocarbon following the Midstream Business’s seasonal conversion of working capital to cash.

 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

 

Commodity Price Risk

 

As of June 30, 2003, approximately 25% of our business (as measured by gross margin, which is defined as revenues less purchased product cost) was directly subject to NGL product price or natural gas risk. Our Maytown gas processing plant in Appalachia and our Michigan operations have percent-of-proceeds contracts. Under percent-of-proceeds contracts, we, as the processor, retain a portion of the sales price of the NGL products produced as compensation for our services. Additionally, we are subject to natural gas price risk as a result of the Pinnacle Acquisition. MarkWest Energy Partners gathers and transports natural gas for producers behind our gathering systems in Texas, many under percent-of-proceeds or percent-of-index contracts. Under these contracts MarkWest Energy Partners is entitled to approximately 10% of the natural gas produced.

 

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. A committee, which includes members of senior management of our general partner, oversees all of our hedging activity.

 

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

 

We enter OTC swaps with 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) 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 NGLs or crude oil or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we may be similarly insulated against unfavorable changes in such prices.

 

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We are also subject to basis risk. Basis risk is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged. 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 typically highly correlated with certain NGL products. We are generally unable to hedge our basis risk for NGL products.

 

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

 

		Year Ending December 31, 2003
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

 

All projected margins or prices on open positions assume (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.

 

We hedge our natural gas price risk in Texas (part of our Pinnacle acquisition) by entering into fixed-for-float swaps or buy puts. As of June 30, 2003, we had hedged our Texas natural gas price risk via swaps as follows:

 

		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, we had hedged our Texas natural gas price risk via puts as follows:

 

		Year Ending December 31,
		2003			2004			2005
MMBtu		184,000			366,000			—
Strike price ($/MMBtu)		$	4.50		$	4.00		$	—

 

Interest Rate Risk

 

We are exposed to changes in interest rates, primarily as a result of our long-term debt under our credit facility with floating interest rates. We 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, 2003, we are 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.

 

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Item 4.  Controls and Procedures

 

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission's rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of June 30, 2003, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of June 30, 2003, our disclosure controls and procedures were effective.

 

There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II.  OTHER INFORMATION

 

Item 6. Exhibits and Reports on Form 8-K

 

(a) Exhibits

 

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, L.P. 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.

 

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

 

A report on Form 8-K was filed with the SEC on June 19, 2003, announcing the Partnership’s June 13, 2003, sale of 300,000 common units, including an option to purchase 75,000 more common units, in a private placement to certain accredited investors.

 

A report on Form 8-K was filed with the SEC on June 25, 2003, concerning the Partnership’s June 24, 2003, press release with respect to midyear financial and operating results.

 

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SIGNATURE

 

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 Energy Partners, L.P. (Registrant)
		By:	MarkWest Energy GP, L.L.C., Its General Partner
Date:     August 14, 2003		By:	/s/ Donald C. Heppermann
			Donald C. Heppermann
			Senior Executive Vice President, Chief Financial Officer and Secretary

 

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