**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  March 31, 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 1-11566**                                                                                                                                                                                                                                                                                 |

** **

**MARKWESTHYDROCARBON, INC.**

(Exact name of registrant as specified in its charter)

** **

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

 

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

(Address of principal executive offices)

 

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

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements for thepast 90 days.

Yes     ý     No     o

 

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

Yes     o     No     ý

 

The registrant had8,496,813 shares of common stock, $.01 per share par value, outstanding as ofMarch 31, 2003.

 

 

----

 
| **PART I—FINANCIAL  INFORMATION**                                                                     |
|------------------------------------------------------------------------------------------------------------|
|                                                                                                       |
| Item 1.  Consolidated Financial Statements                                                            |
| Consolidated Balance Sheet  at March 31, 2003 and December 31, 2002                                        |
| Consolidated  Statement of Operations for the Three Months Ended March 31, 2003 and 2002                   |
| Consolidated  Statement of Cash Flows for the Three Months Ended March 31, 2003 and 2002                   |
| Consolidated  Statement of Changes in Stockholders’ Equity for the Three Months Ended March  31, 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 6.  Exhibits and Reports on Form 8-K                                                             |
|                                                                                                       |
| **SIGNATURE**                                                                                              |
|                                                                                                       |
| **CERTIFICATIONS**                                                                                         |

 

#### **Glossaryof Terms**

 
| Bcf    |   | billion cubic feet of  natural gas                                  |
|--------|--------|---------------------------------------------------------------------|
| Btu    |   | British thermal units,  an energy measurement                       |
| Gal/d  |   | gallons per day                                                     |
| Mcf    |   | thousand cubic feet of  natural gas                                 |
| Mcf/d  |   | thousand cubic feet of  natural gas per day                         |
| 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                          |
| NGL    |   | natural gas liquids,  such as propane, butanes and natural gasoline |

 

One barrel of oil or NGLis the energy equivalent of six Mcf of natural gas.

 

2

----

 

## **PARTI—FINANCIAL INFORMATION**

## **Item1.  Consolidated Financial Statements**

 

**MARKWEST HYDROCARBON, INC.**

**CONSOLIDATED BALANCE SHEETS**

**(UNAUDITED)**

**(inthousands except share and per share data)**

** **
|                                                                                                               |   | **March 31,****2003** |    | **December 31,****2002** |   |
|--------------------------------------------------------------------------------------------------------------------|--------|-----------------------|---------|--------------------------|--------|
| **ASSETS**                                                                                                         |   |                  |    |                     |   |
| **Current  assets:**                                                                                               |   |                  |    |                     |   |
| Cash  and cash equivalents                                                                                         |   | $                     | 7,908   |                     | $      | 6,410 |   |
| Receivables,  net (including related party receivables of $1,143 and $748, respectively)                           |   | 38,446                |    | 25,444                   |   |
| Inventories                                                                                                        |   | 3,223                 |    | 4,347                    |   |
| Prepaid  replacement natural gas                                                                                   |   | 2,104                 |    | 1,197                    |   |
| Other  assets                                                                                                      |   | 1,310                 |    | 1,240                    |   |
| Total  current assets                                                                                              |   | 52,991                |    | 38,638                   |   |
|                                                                                                               |   |                  |    |                     |   |
| Property,  plant and equipment:                                                                                    |   |                  |    |                     |   |
| Gas  processing, gathering, storage and marketing equipment                                                        |   | 159,614               |    | 121,851                  |   |
| Oil  and gas properties and equipment, full cost method                                                            |   | 154,164               |    | 139,234                  |   |
| Land,  buildings and other equipment                                                                               |   | 7,627                 |    | 7,540                    |   |
| Construction  in progress                                                                                          |   | 1,640                 |    | 1,610                    |   |
|                                                                                                               |   | 323,045               |    | 270,235                  |   |
| Less:  accumulated depreciation, depletion and amortization                                                        |   | (65,469               | )       | (58,717                  | )      |
| Total  property and equipment, net                                                                                 |   | 257,576               |    | 211,518                  |   |
|                                                                                                               |   |                  |    |                     |   |
| Risk  management asset                                                                                             |   | 638                   |    | 749                      |   |
| Intangible  assets, net of accumulated amortization of $2,150 and $2,018, respectively                             |   | 2,605                 |    | 2,138                    |   |
| Note  receivables from employees                                                                                   |   | 271                   |    | 271                      |   |
|                                                                                                               |   |                  |    |                     |   |
| Total  assets                                                                                                      |   | $                     | 314,081 |                     | $      | 253,314 |   |
|                                                                                                               |   |                  |    |                     |   |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                     |   |                  |    |                     |   |
|                                                                                                               |   |                  |    |                     |   |
| Current  liabilities:                                                                                              |   |                  |    |                     |   |
| Accounts  payable (including related party payables of $1,893 and $1,264, respectively)                            |   | $                     | 44,596  |                     | $      | 26,063 |   |
| Accrued  liabilities                                                                                               |   | 8,178                 |    | 8,145                    |   |
| Risk  management liability                                                                                         |   | 13,960                |    | 13,719                   |   |
| Total  current liabilities                                                                                         |   | 66,734                |    | 47,927                   |   |
|                                                                                                               |   |                  |    |                     |   |
| Deferred  income taxes                                                                                             |   | 33,666                |    | 35,685                   |   |
| Long-term  debt                                                                                                    |   | 105,824               |    | 64,223                   |   |
| Risk  management liability                                                                                         |   | 1,761                 |    | 2,115                    |   |
| Other  long-term liabilities                                                                                       |   | 6,646                 |    | 4,011                    |   |
| Minority  interest in consolidated subsidiary                                                                      |   | 45,345                |    | 46,001                   |   |
| Commitments  and contingencies                                                                                     |   |                  |    |                     |   |
|                                                                                                               |   |                  |    |                     |   |
| Stockholders’  equity:                                                                                        |   |                  |    |                     |   |
| Preferred  stock, par value $0.01, 5,000,000 shares authorized, 0 shares outstanding                               |   | —                |    | —                   |   |
| Common  stock, par value $0.01, 20,000,000 shares authorized, 8,561,374 and 8,561,374  shares issued, respectively |   | 87                    |    | 87                       |   |
| Additional  paid-in capital                                                                                        |   | 42,747                |    | 42,758                   |   |
| Retained  earnings                                                                                                 |   | 18,651                |    | 19,693                   |   |
| Accumulated  other comprehensive income (loss), net of tax                                                         |   | (6,987                | )       | (8,858                   | )      |
| Treasury  stock, 64,561 and 50,461 shares, respectively                                                            |   | (393                  | )       | (328                     | )      |
| Total  stockholders’ equity                                                                                   |   | 54,105                |    | 53,352                   |   |
|                                                                                                               |   |                  |    |                     |   |
| Total  liabilities and stockholders’ equity                                                                   |   | $                     | 314,081 |                     | $      | 253,314 |   |

 

The accompanyingnotes are an integral part of these financial statements.

 

3

----

 

**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATED STATEMENTS OF OPERATIONS**

**(UNAUDITED)**

** **
|                                                                                    |   | **Three Months Ended****March 31,**        |   |
|-----------------------------------------------------------------------------------------|--------|--------------------------------------------|--------|
|                                                                                    |   | **2003**                                   |   | **2002** |   |
|                                                                                    |   | **(in  thousands, except per share data)** |   |
| Revenue:                                                                                |   |                                       |   |   |   |
| Gathering,  processing and marketing                                                    |   | $                                          | 50,651 |   | $ | 37,330 |   |
| Exploration  and production                                                             |   | 10,659                                     |   | 7,057 |   |
| Total  revenue                                                                          |   | 61,310                                     |   | 44,387 |   |
|                                                                                    |   |                                       |   |   |   |
| Operating  expenses:                                                                    |   |                                       |   |   |   |
| Purchased  gas costs                                                                    |   | 46,003                                     |   | 28,088 |   |
| Plant  operating expenses                                                               |   | 4,506                                      |   | 4,350 |   |
| Lease  operating expenses                                                               |   | 1,608                                      |   | 1,252 |   |
| Transportation  costs                                                                   |   | 513                                        |   | 338 |   |
| Production  taxes                                                                       |   | 728                                        |   | 283 |   |
| Selling,  general and administrative expenses                                           |   | 3,137                                      |   | 2,827 |   |
| Depreciation,  depletion and amortization                                               |   | 5,098                                      |   | 5,214 |   |
| Total  operating expenses                                                               |   | 61,593                                     |   | 42,352 |   |
|                                                                                    |   |                                       |   |   |   |
| Income  (loss) from operations                                                          |   | (283                                       | )      | 2,035 |   |
|                                                                                    |   |                                       |   |   |   |
| Other  income and (expenses):                                                           |   |                                       |   |   |   |
| Interest  income                                                                        |   | 24                                         |   | 7 |   |
| Interest  expense                                                                       |   | (1,087                                     | )      | (1,052 | ) |
| Write-down  of deferred financing costs                                                 |   | —                                     |   | (718 | ) |
| Minority  interest in net income of consolidated subsidiary                             |   | (874                                       | )      | — |   |
| Other  income (expense)                                                                 |   | (15                                        | )      | 2 |   |
|                                                                                    |   |                                       |   |   |   |
| Income  (loss) before income taxes                                                      |   | (2,235                                     | )      | 274 |   |
|                                                                                    |   |                                       |   |   |   |
| Provision  (benefit) for income taxes:                                                  |   |                                       |   |   |   |
| Current                                                                                 |   | (23                                        | )      | 83 |   |
| Deferred                                                                                |   | (1,199                                     | )      | 16 |   |
| Provision  (benefit) for income taxes                                                   |   | (1,222                                     | )      | 99 |   |
|                                                                                    |   |                                       |   |   |   |
| Income  (loss) before change in accounting principle                                    |   | (1,013                                     | )      | 175 |   |
|                                                                                    |   |                                       |   |   |   |
| Cumulative  effect of change in accounting for asset retirement obligations, net of tax |   | (29                                        | )      | — |   |
|                                                                                    |   |                                       |   |   |   |
| Net  income (loss)                                                                      |   | $                                          | (1,042 | ) | $ | 175 |   |
|                                                                                    |   |                                       |   |   |   |
| Basic  earnings (loss) per share of common stock                                        |   | $                                          | (0.12  | ) | $ | 0.02 |   |
| Earnings  (loss) per share assuming dilution                                            |   | $                                          | (0.12  | ) | $ | 0.02 |   |
|                                                                                    |   |                                       |   |   |   |
| Weighted  average number of outstanding shares of common stock:                         |   |                                       |   |   |   |
| Basic                                                                                   |   | 8,511                                      |   | 8,515 |   |
| Assuming  dilution                                                                      |   | 8,514                                      |   | 8,528 |   |

 

The accompanyingnotes are an integral part of these financial statements.

 

4

----

 

**MARKWEST HYDROCARBON, INC.**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(UNAUDITED)**

 
|                                                                               |   | **Three Months Ended  March 31,** |   |
|------------------------------------------------------------------------------------|--------|-----------------------------------|--------|
|                                                                               |   | **2003**                          |   | **2002** |   |
|                                                                               |   | **(in  thousands)**               |   |
| **Cash flows from operating activities:**                                          |   |                              |   |   |   |
| Net  income (loss)                                                                 |   | $                                 | (1,042 | ) | $ | 175 |   |
| Adjustments  to reconcile net income to net cash provided by operating activities: |   |                              |   |   |   |
| Cumulative  effect of change in accounting                                         |   | 29                                |   | — |   |
| Depreciation,  depletion and amortization                                          |   | 5,098                             |   | 5,214 |   |
| Amortization  of deferred financing costs included in interest expense             |   | 309                               |   | 306 |   |
| Write-off  of deferred financing costs                                             |   | —                            |   | 718 |   |
| Minority  interest in net income of consolidated subsidiary                        |   | 874                               |   | — |   |
| Derivative  ineffectiveness and non-cash mark-to-market adjustment                 |   | (922                              | )      | (75 | ) |
| Reclassification  of Enron hedges to purchased gas costs                           |   | (18                               | )      | (420 | ) |
| Deferred  income taxes                                                             |   | (1,199                            | )      | 16 |   |
| Other                                                                              |   | 240                               |   | 24 |   |
| Changes  in operating assets and liabilities:                                      |   |                              |   |   |   |
| (Increase)  decrease in receivables                                                |   | (3,844                            | )      | (1,557 | ) |
| (Increase)  decrease in inventories                                                |   | 1,124                             |   | 2,433 |   |
| (Increase)  decrease in prepaid expenses and other assets                          |   | (873                              | )      | 7,503 |   |
| Increase  (decrease) in accounts payable and accrued liabilities                   |   | 9,773                             |   | 1,703 |   |
| Increase  (decrease) in other long-term liabilities                                |   | —                            |   | 3,090 |   |
|                                                                               |   |                              |   |   |   |
| Net  cash flow provided by operating activities                                    |   | 9,549                             |   | 19,130 |   |
|                                                                               |   |                              |   |   |   |
| **Cash flows from investing activities:**                                          |   |                              |   |   |   |
| Pinnacle  acquisition, net of cash acquired                                        |   | (38,238                           | )      | — |   |
| Capital  expenditures                                                              |   | (6,735                            | )      | (9,113 | ) |
| Proceeds  from sale of assets                                                      |   | 24                                |   | 42 |   |
|                                                                               |   |                              |   |   |   |
| Net  cash used in investing activities                                             |   | (44,949                           | )      | (9,071 | ) |
|                                                                               |   |                              |   |   |   |
| **Cash flows from financing activities:**                                          |   |                              |   |   |   |
| Proceeds  from long-term debt                                                      |   | 45,700                            |   | 4,500 |   |
| Repayment  of long-term debt                                                       |   | (6,500                            | )      | (16,300 | ) |
| Debt  issuance costs                                                               |   | (810                              | )      | (236 | ) |
| Distribution  to MarkWest Energy Partners’ unitholders                        |   | (1,530                            | )      | — |   |
| Net  issuance of treasury shares                                                   |   | (76                               | )      | 76 |   |
|                                                                               |   |                              |   |   |   |
| Net  cash provided by (used in) financing activities                               |   | 36,784                            |   | (11,960 | ) |
|                                                                               |   |                              |   |   |   |
| Effect  of exchange rate on changes in cash                                        |   | 114                               |   | 3 |   |
|                                                                               |   |                              |   |   |   |
| Net  increase (decrease) in cash and cash equivalents                              |   | 1,498                             |   | (1,898 | ) |
| Cash  and cash equivalents at beginning of period                                  |   | 6,410                             |   | 2,340 |   |
|                                                                               |   |                              |   |   |   |
| Cash  and cash equivalents at end of period                                        |   | $                                 | 7,908  |   | $ | 442 |   |

 

The accompanying notes are an integral part ofthese financial statements.

 

5

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**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATED STATEMENTOF 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                            | )      | $                 | 87     |                             | $      | 42,758                 |   | $                     | 19,693 |                                                 | $      | (328                                  | )      | $ | (8,858 | ) | $ | 53,352 |   |
|                                           |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                 |   |                                  |   |
| Comprehensive  income:                         |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                 |   |                                  |   |
| Net  income (loss)                             |   | —                       |   | —                         |   | —            |   | —                           |   | (1,042                 | )      | —                |   | —                                               |   | (1,042                                | )      |
| Other  comprehensive income:                   |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                 |   |                                  |   |
| Foreign  currency translation, net of tax      |   | —                       |   | —                         |   | —            |   | —                           |   | —                 |   | —                |   | 2,264                                                |   | 2,264                                 |   |
| Risk  management activities, net of tax        |   | —                       |   | —                         |   | —            |   | —                           |   | —                 |   | —                |   | (393                                                 | )      | (393                                  | )      |
| Comprehensive  income, net of tax              |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                 |   | $                                     | 829    |   |
|                                           |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                 |   |                                  |   |
| Net  treasury stock (acquisitions) reissuances |   | —                       |   | (15                            | )      | —            |   | (11                              | )      | —                 |   | (65                   | )      | —                                               |   | (76                                   | )      |
|                                           |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                 |   |                                  |   |
| Balance,  March 31, 2003                       |   | 8,561                        |   | (65                            | )      | $                 | 87     |                             | $      | 42,747                 |   | $                     | 18,651 |                                                 | $      | (393                                  | )      | $ | (6,987 | ) | $ | 54,105 |   |

 

The accompanyingnotes are an integral part of these financial statements.

 

6

----

 

**MARKWESTHYDROCARBON, INC.**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)**

 

**1.****              General**

 

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

 

We have prepared the unaudited financial statementspresented herein in accordance with the instructions to Form 10-Q.  The statements do not include all theinformation and note disclosures required by generally accepted accountingprinciples for complete financial statements. Please read the interim consolidated financial statements in conjunctionwith the Consolidated Financial Statements and attached notes for the yearended December 31, 2002, included in our Annual Report on Form 10-K, as filedwith the Securities and Exchange Commission. In the opinion of management, we have made all necessary adjustments fora fair statement of the results for the unaudited interim periods.  These are only normal recurring adjustments.

 

We base the effective corporate tax rate for interimperiods on the estimated annual effective corporate tax rate.  The effective tax rate varies from statutoryrates primarily due to permanent differences in Canada.  The variance between the effective tax ratefor the three months ended March 31, 2003 and statutory rates was impacted byan operating loss in the U.S. combined with operating income in Canada.

 

**2.****              PinnacleAcquisition**

 

On March 28, 2003, our consolidated subsidiary,MarkWest Energy Partners, L.P. (“MarkWest Energy Partners”), completed theacquisition of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNGTransmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc.(collectively, the “Sellers”).  Thepurchase price was comprised of $23.4 million paid in cash to the Sellers, plusthe assumption of specified liabilities, including $16.6 million of bankindebtedness.

 

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

 

The purchase price was allocated as follows (inthousands):

 
| 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 |   |
| Oil  and gas properties-proved    |   | 37,428 |   |
| Total                             |   | $      | 48,071 |   |

 

7

----

 

*Pro Forma Results of Operations(Unaudited)*

 

The following tablereflects the unaudited pro forma consolidated results of operations for thethree months ended March 31, 2003 and 2002, as though our Pinnacle acquisitionhad occurred on January 1, 2002. These unaudited pro forma results have beenprepared for comparative purposes only and are not indicative of futureresults.

 

 
|                                                |   | **Three  Months Ended March 31,**          |   |
|-----------------------------------------------------|--------|--------------------------------------------|--------|
|                                                |   | **2003**                                   |   | **2002** |   |
|                                                |   | **(in  thousands, except per share data)** |   |
| Revenue                                             |   | $                                          | 79,097 |   | $ | 52,429 |   |
| Net  income (loss)                                  |   | $                                          | (327   | ) | $ | (41 | ) |
| Basic  net income (loss) per limited partner unit   |   | $                                          | (0.04  | ) | $ | 0.00 |   |
| Diluted  net income (loss) per limited partner unit |   | $                                          | (0.04  | ) | $ | 0.00 |   |

 

**3.     Liquidity**

 

MarkWest Hydrocarbon’s cash flow generated fromoperations is subject to volatility in energy prices, especially prices forNGLs and natural gas. Our cash flow is enhanced in periods when the pricesreceived for NGLs are high relative to the price of natural gas we purchase tosatisfy our “keep-whole” contractual arrangements in Appalachia, and is reducedin periods when the prices received for NGLs are low relative to the price ofnatural gas we purchase to satisfy such contractual arrangements. Under“keep-whole” contracts, we retain and sell the NGLs produced in our processingoperations for third-party producers, and then reimburse or “keep whole” theproducers for the Btu content of the NGLs removed through the re-delivery tothe producers of an equivalent amount (on a Btu basis) of dry natural gas.  Generally, the value of the NGLs extractedis greater than the cost of replacing those Btus with dry gas, resulting inpositive operating margins under these contracts. Periodically, when naturalgas becomes more expensive, on a Btu equivalent basis, than NGL products, thecost of keeping the producer “whole” can result in operating losses.

 

Toward the end of the first quarter of 2003, naturalgas prices began to be unusually high compared to NGL prices. This trend isforecast to continue through at least the second quarter of 2003.  This unusual disparity in prices has reducedour internally generated cash flows, will likely cause limitations on theavailability of borrowings under our credit facility, and may cause us to be innoncompliance with certain financial covenants under the credit facility.

 

We have commenceddiscussions with the lenders under our credit facility and believe that we willbe able to obtain covenant waivers should noncompliance occur. However, webelieve that during any period of noncompliance, borrowings under the creditfacility would be limited to amounts currently available, exclusive of MarkWestEnergy Partners’ credit facility. As of March 31, 2003, MarkWest Hydrocarbonhas borrowed $44.7 million of the $52.9 million available credit under our$60 million credit facility.

 

In light of theforecasted reduction in cash flows and possible limits on available borrowingsunder our credit facility, MarkWest Hydrocarbon has undertaken a series ofinitiatives to enhance our liquidity position and to take advantage offavorable market valuations of domestic exploration and production assets.  Accordingly, we have engaged a third partyto act as financial advisor to MarkWest Hydrocarbon to assist in solicitingacquisition proposals for certain of our developed oil and gas properties. Theexpected sale proceeds from these properties would substantially improve ourliquidity and allow us to maintain full compliance with our credit facilitycovenants.

 

Almost all of our capitalexpenditures are discretionary.  We willtherefore manage our future capital expenditures to match available cash flowsfrom operations.

 

8

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**4.     Debt**

 

*MarkWestHydrocarbon, Inc.*

 

In conjunction with the Pinnacle acquisition (see Note2), MarkWest Hydrocarbon amended its credit agreement (the “Credit Facility”)with various lenders effective March 28, 2003. The amended agreement providesfor a ratio of not more than 3.75:1.00 of Total Funded Debt (as defined in theCredit Facility) to EBITDA (as defined in the Credit Facility) for the fourmost recently completed fiscal quarters, reducing to 3.50 as of September 30,2003, and to 3.0 as of March 31, 2004 and thereafter. All other aspects of theamended agreement, including rates, collateralization and covenants are similarto the original agreement.

 

*MarkWestEnergy Partners*

 

In conjunction with the Pinnacle acquisition (see Note2), MarkWest Energy Partners amended its credit agreement with various lenderseffective March 28, 2003.  The amendedagreement provides for a $15 million increase to our maximum borrowing amount,now $75 million.  All other aspects ofthe amended agreement, including rates, collateralization and covenants are similarto the original agreement.

 

#### **5.     Adoption of SFAS No. 143**

# *** ***

On January 1, 2003, we adopted SFAS No. 143, *Asset Retirement Obligations*.  SFAS No. 143 requires entities to record thefair value of a liability for an asset retirement obligation in the period inwhich it is incurred and a corresponding increase in the carrying amount of therelated long-lived asset.  Subsequently,the asset retirement cost should be allocated to expense using a systematic andrational method.  During the firstquarter of 2003, we recorded a net-of-tax cumulative effect of change inaccounting principle charge of $29,000 ($63,000 before tax), an assetretirement obligation of $3.2 million (a net increase to long-term liabilitiesof $2.5 million). We also increased net properties $2.4 million in accordancewith 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 retirementobligation would have been $2.5 million at January 1, 2002 had we adopted SFAS No.143 on January 1, 2002.    The assetretirement obligation, which is included on the Consolidated Balance Sheet inOther Long-Term Liabilities, was $2.4 million at March 31, 2003.

 

For the period endedMarch 31, 2002, the pro forma effect on net income and earnings per share, hadSFAS No. 143 been adopted by us on January 1, 2002, would have been as follows:

 
|                 |   | **As  Reported**                           |   | **Pro  Forma** |   |
|----------------------|--------|--------------------------------------------|--------|----------------|--------|
|                 |   | **(in  thousands, except per share data)** |   |
| Net  income          |   | $                                          | 175    |           | $      | (173 | ) |
| Earnings  per share: |   |                                       |   |           |   |
| Basic                |   | $                                          | 0.02   |           | $      | (0.02 | ) |
| Diluted              |   | $                                          | 0.02   |           | $      | (0.02 | ) |

 

**6.     Assets Held for Sale**

 

Our board of directors has approved a plan to sell ourthree NGL product terminals, which are considered to be non-strategicassets.  The terminals’ combined netbook value as of March 31, 2003 was approximately $2.7 million.  We believe the results from these terminalsare immaterial for separate presentation as a discontinued operation.

 

**7.     Segment Reporting**

 

Our operations areclassified into three reportable segments:

 

(1)          Exploration and Production—explorefor and produce natural gas;

 

9

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

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

 

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

 

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

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

 

Although first quarter of 2003 reflects our new segments,information prior to May 24, 2002 has not been restated to reflect the changein segmentation because no transfer pricing existed between Gathering andProcessing and Marketing up until that point in time. In connection with theformation of MarkWest Energy Partners, certain contracts were executed whichestablished the basis of fees for services rendered by processing MarkWestHydrocarbon’s natural gas.  No sucharrangement existed prior to the formation of MarkWest Energy Partners.  As a result, it is not practicable torestate certain prior period segment information to conform to our currentpresentation.

 

We evaluate theperformance of our segments and allocate resources to them based on operatingincome.  There were no intersegmentrevenues prior to May 24, 2002.  Weconduct our business in the United States and Canada.

 

The table below presents information about operatingincome for the reported segments for the three months ended March 31, 2003 and2002. Operating income for each segment includes total revenues less purchasedproducts costs, operating expenses, depreciation and depletion and excludesselling, general and administrative expenses, interest expense, interestincome, one-time charges and income taxes. We have not reported asset informationby reportable segment because we do not produce such information internally.

 
|                                      |   | **MarkWest Hydrocarbon**        |   |
|-------------------------------------------|--------|---------------------------------|--------|
|                                      |   |                            |   |   |   |   |   |   |   | **MarkWest  Energy  Partners** |   |   |   |
|                                      |   | **Exploration  and Production** |   | **Marketing** |   | **Gathering  Processing &** |   |   |   |
|                                      |   | **U.S.**                        |   | **Canada** |   | **Total** |   | **U.S.** |   | **U.S.** |   | **Total** |   |
| **Three  Months Ended****March 31, 2003** |   |                            |   |   |   |   |   |   |   |   |   |   |   |
| Revenues                                  |   | $                               | 4,242  |   | $ | 6,417 |   | $ | 10,659 |   | $ | 32,958 |   | $ | 17,693 |   | $ | 61,310 |   |
| Segment  operating income                 |   | $                               | 1,960  |   | $ | 2,278 |   | $ | 4,238 |   | $ | (5,003 | ) | $ | 3,619 |   | $ | 2,854 |   |

 
|                                   |   | **Exploration  and Production** |   | **Gathering  Processing &  Marketing** |   |      |   |
|----------------------------------------|--------|---------------------------------|--------|--------------------------------------------|--------|-----------|--------|
|                                   |   | **U.S.**                        |   | **Canada**                                 |   | **Total** |   | **U.S** |   | **Total** |   |
| **Three  Months Ended March 31, 2002** |   |                            |   |                                       |   |      |   |   |   |   |   |
| Revenues                               |   | $                               | 2,357  |                                       | $      | 4,700     |   | $ | 7,057 |   | $ | 37,330 |   | $ | 44,387 |   |
| Segment  operating income              |   | $                               | 849    |                                       | $      | 212       |   | $ | 1,061 |   | $ | 3,801 |   | $ | 4,862 |   |

 

10

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A reconciliation of totalsegment operating income to total consolidated income before taxes is asfollows:

 
|                                                                  |   | **Three  Months Ended March 31,** |   |
|-----------------------------------------------------------------------|--------|-----------------------------------|--------|
|                                                                  |   | **2003**                          |   | **2002** |   |
| Total  segment operating income                                       |   | $                                 | 2,854  |   | $ | 4,862 |   |
| Selling,  general and administrative expenses administrative expenses |   | (3,137                            | )      | (2,827 | ) |
| Interest  income                                                      |   | 24                                |   | 7 |   |
| Interest  expense                                                     |   | (1,087                            | )      | (1,052 | ) |
| Write-down  of deferred financing costs                               |   | —                            |   | (718 | ) |
| Minority  interest in net income of consolidated subsidiary           |   | (874                              | )      | — |   |
| Other  income (expense)                                               |   | (15                               | )      | 2 |   |
| Income  (loss) before taxes                                           |   | $                                 | (2,235 | ) | $ | 274 |   |

 

**8.     Commitmentsand Contingencies**

 

We are involved invarious litigation and administrative proceedings arising in the normal courseof business. In the opinion of management, any liabilities that may result fromthese claims will not, individually or in the aggregate, have a materialadverse effect on our financial position or results of operations.

 

**9.     Stockand Unit Compensation**

 

As permitted under SFASNo. 123, *Accountingfor Stock-Based Compensation,*we have elected to continue to measurecompensation costs for stock-based and unit-based employee compensation plansas prescribed by Accounting Principles Board Opinion No. 25, *Accountingfor Stock Issued to Employees.*We have two fixed compensation plansand, through our consolidated subsidiary, MarkWest Energy Partners, we have avariable plan. We account for these plans using fixed and variable accountingas appropriate.

 

Had compensation cost forour two stock-based compensation plans been determined based on the fair valueat the grant dates under those plans consistent with the method prescribed bySFAS No. 123.**our net income and earnings (loss) per share would havebeen reduced to the pro forma amounts listed below:

 

|                                                                                                                                         |   | **Three  Months Ended March 31,**      |   |
|----------------------------------------------------------------------------------------------------------------------------------------------|--------|----------------------------------------|--------|
|                                                                                                                                         |   | **2003**                               |   | **2002** |   |
|                                                                                                                                         |   | **(in  thousands, except share data)** |   |
| Net  income (loss), as reported                                                                                                              |   | $                                      | (1,042 | ) | $ | 175 |   |
| Deduct:  total stock-based employee compensation expense determined under fair value  based method for all awards, net of related tax effect |   | (73                                    | )      | (136 | ) |
| Pro  forma net income (loss)                                                                                                                 |   | $                                      | (1,115 | ) | $ | 39 |   |
|                                                                                                                                         |   |                                   |   |   |   |
| Earnings  (loss) per share:                                                                                                                  |   |                                   |   |   |   |
| Basic,  as reported                                                                                                                          |   | $                                      | (0.12  | ) | $ | 0.02 |   |
| Basic,  pro forma                                                                                                                            |   | $                                      | (0.13  | ) | $ | 0.00 |   |
| Diluted,  as reported                                                                                                                        |   | $                                      | (0.12  | ) | $ | 0.02 |   |
| Diluted,  pro forma                                                                                                                          |   | $                                      | (0.13  | ) | $ | 0.00 |   |

 

Compensation expense for the variable plan, includingrestricted unit grants, is measured using the market price of MarkWest EnergyPartners’ common units on the date the number of units in the grant becomesdeterminable and is amortized into earnings over the period of service. Ourstock options are issued under a fixed plan. Accordingly, compensation expenseis not recognized for stock options unless the options were granted at anexercise price lower than market on the grant date.

 

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##### **Item2.   Management’s Discussion andAnalysis of Financial Condition and Results of Operations**

 

**Forward-LookingInformation**

 

Statements included inthis Management’s Discussion and Analysis that are not historical facts areforward-looking statements within the meaning of Section 27A of the SecuritiesAct of 1933, as amended, and Section 21E of the Securities and Exchange Act of1934, as amended.  We use words such as“may,” “believe,” “estimate,” “expect,” “plan,” “intend,” “project,”“anticipate,” and similar expressions to identify forward-lookingstatements.  We have based these forward-lookingstatements on our current expectations and projections about future events,activities or developments.  Our actualresults could differ materially from those discussed in our forward-lookingstatements.  Forward-looking statementsinclude statements relating to, among other things:

 

•                  ourplans for pursuing future exploration projects

•                  ourproduction plans

•                  ourexpectations regarding gas prices

•                  ourestimates of quantities of proven oil and gas reserves

•                  ourprojections of rates of production and timing of development expenditures

•                  ourefforts to increase fee-based contract volumes

•                  ourability to maximize the value of our NGL output

•                  theadequacy of our general public liability, property, and business interruptioninsurance

•                  ourability to comply with environmental and governmental regulations

•                  ourexpectations regarding MarkWest Energy Partners, L.P.

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

•                  thesuccess of our efforts to improve our liquidity position

 

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

 

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

•                  theavailability and prices of NGL and competing commodities

•                  theeffectiveness of our NGL hedging activities

•                  theavailability and prices of raw natural gas supply

•                  ourability to negotiate favorable marketing agreements

•                  therisks that third party or MarkWest Hydrocarbon’s natural gas exploration andproduction activities will not occur or be successful

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

•                  competitionfrom other NGL processors, including major energy companies

•                  ourability to identify and consummate grass-roots projects or acquisitionscomplementary to our business

•                  winterweather conditions

•                  changesin foreign economics, currency, and laws and regulations in Canada whereMarkWest Hydrocarbon has made direct investments

•                  ourability to estimate quantities of proven oil and gas reserves

•                  ourability to project rates of production

•                  ourability to project the timing of developmental expenditures

•                  ourability to manage the risks inherent in drilling wells

•                  theability of the Partnership to make distributions to MarkWest Hydrocarbon andthe other limited partners

 

Forward-lookingstatements involve many uncertainties that are beyond our ability tocontrol.  In many cases, we cannotpredict what factors would cause actual results to differ materially from thoseindicated by the forward-looking statements.

 

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**PinnacleAcquisition**

 

On March 28, 2003, ourconsolidated subsidiary, MarkWest Energy Partners, L.P. (“MarkWest EnergyPartners”), completed the acquisition of Pinnacle Natural Gas Company, PinnaclePipeline Company, PNG Transmission Company, Inc., PNG Utility Company andBright Star Gathering, Inc. (collectively, the “Sellers”).  The purchase price was comprised of $23.4million paid in cash to the Sellers, plus the assumption of specifiedliabilities, including $16.6 million of bank indebtedness.

 

The acquisition wasaccomplished through a merger under Texas law of the Sellers and four newlyformed wholly owned subsidiaries of MarkWest Energy Partners as buyers.  In the merger, most of the assets andliabilities of the Sellers were allocated to the MarkWest Energy Partnersentities, and all entities survived the merger.  The assets acquired from the Sellers, primarily located in thestate of Texas, with the balance located in New Mexico, Louisiana, Mississippiand Kansas, are comprised of three lateral natural gas pipelines and twentygathering systems.  The three lateralnatural gas pipelines consist of approximately 67 miles of pipe and transportup to 1.1 Bcf/day under firm contracts to power plants.  The twenty gathering systems gather morethan 44 MMcf/d.

 

**Results of Operations**

 

*Operating Data*

 
|                                |   | **Three  Months Ended March 31,** |   |
|-------------------------------------|--------|-----------------------------------|--------|
|                                |   | **2003**                          |   | **2002** |   | **% Change** |   |
|                                |   |                              |   |   |   |   |   |
| Exploration and production          |   |                              |   |   |   |   |   |
| Natural gas produced (Mcfe/d)       |   | 27,500                            |   | 29,200 |   | (6 | %) |
|                                |   |                              |   |   |   |   |   |
| MarkWest Energy Partners            |   |                              |   |   |   |   |   |
| Appalachia:                         |   |                              |   |   |   |   |   |
| Natural gas processed (Mcf/d)       |   | 264,000                           |   | 269,000 |   | (2 | %) |
| NGLs fractionated for a fee (gal/d) |   | 446,000                           |   | 479,000 |   | (7 | %) |
|                                |   |                              |   |   |   |   |   |
| Michigan:                           |   |                              |   |   |   |   |   |
| Natural gas processed for a fee     |   | 15,400                            |   | 11,000 |   | 40 | % |

 

***Three Months Ended March 31, 2003 Compared to the ThreeMonths Ended March 31, 2002***

## ** **

*Net loss.* Net loss was $1.0million for the three months ended March 31, 2003, compared to net income of$0.2 million for the three months ended March 31, 2002. The continuingunfavorable results from our hedges primarily caused our first quarter 2003 netloss.  Hedging losses more than offsetthe benefits from the high natural gas prices that prevailed throughout thefirst quarter of 2003.

 

*Gathering, processing and marketingrevenue.* Gathering, processing and marketing revenue was$50.7 million for the three months ended March 31, 2003 compared to$37.3 million for the three months ended March 31, 2002, an increase of$13.3 million, or 36%. Revenue was higher in 2003 than in 2002 primarilydue to:

 

•                  IncreasedNGL product sales prices in Appalachia, which increased revenues $10.4 million,net of $7.3 million of hedging losses in 2003. Price increases offset modest Appalachian volume declines, which pushedrevenues down $1.4 million.

•                  Increasedvolumes, up 40%, and prices, up 109%, in Michigan contributed an additional$1.3 million in 2003.

•                  OurMarch 2003 Pinnacle acquisition increased revenues $0.8 million.

•                  Gasmarketing revenues increased $0.6 million.

 

*Exploration andproduction revenue. *Exploration and production revenue was $10.7million for the three months ended March 31, 2003 compared to $7.1 millionfor the three months ended March 31, 2002, an increase of

 

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$3.6 million, or 60%. Revenue was higher in 2003 than in 2002primarily due to higher natural gas prices, partially offset by volumedecreases. Revenue increased despite $1.5 million in hedging losses in 2003.

 

*Purchased gascosts.*  Purchased gas costs were $46.0 million forthe three months ended March 31, 2003, compared to $28.1 million for thethree months ended March 31, 2002, an increase of $17.9 million, or 64%.Purchased gas costs were higher in 2003 primarily due to:

 

•                  Increasednatural gas and NGL product prices in Appalachia, which increased purchasedproduct costs $15.2 million.  Priceincreases offset modest Appalachian volume declines, which pushed purchasedproduct costs down $1.1 million. Purchased gas costs increased more thangathering, processing and marketing revenues.

•                  Increasedvolumes, up 40%, and prices, up 109%, in Michigan contributed an additional$0.4 million in 2003.

•                  OurMarch 2003 Pinnacle acquisition increased purchased product costs $0.7 million.

•                  Gasmarketing product purchase costs increased $0.8 million.

 

*Plant operatingexpenses.*  Plant operating expenses were$4.5 million for the three months ended March 31, 2003, compared to$4.4 million for the three months ended March 31, 2002, an increase of$0.2 million, or 4%.

 

*Lease operatingexpenses.*  Lease operating expenses were$1.6 million for the three months ended March 31, 2003, compared to $1.3million for the three months ended March 31, 2002, an increase of$0.4 million, or 29%. Lease operating expenses increased principally dueto additional workovers and recompletions of wells in Canada in 2003.

* *

*Transportationcosts. *Transportation costs were $0.5 million forthe three months ended March 31, 2003, compared to $0.3 million for thethree months ended March 31, 2002, an increase of $0.2 million, or 35%.Transportation costs increased principally due to a 36% increase in ourthroughput from our U.S. properties.  Weprovide the majority of our Canadian transportation.

 

*Production taxes. *Production taxes were$0.7 million for the three months ended March 31, 2003, compared to$0.3 million for the three months ended March 31, 2002, an increase of$0.4 million, or 158%. Production taxes increased principally due toincreased natural gas prices in 2003.

 

*Selling,*g*eneral and administrative expenses.*  Selling, general and administrative expenseswere $3.1 million for the three months ended March 31, 2003, compared to $2.8million for the three months ended March 31, 2002, an increase of$0.3 million, or 11%.  The increaseis principally attributable to increased insurance costs and incremental costsassociated with our consolidated subsidiary, MarkWest Energy Partners, whichwent public in May 2002.

 

*Depreciationand depletion.*  Depreciation and depletion were$5.1 million for the three months ended March 31, 2003, compared to$5.2 million, for the three months ended March 31, 2002, a decrease of$0.1 million, or 2%.

 

*Interestexpense.*  Interest expense was $1.1 million for boththe three months ended March 31, 2003, and March 31, 2002.  The expensing of third party costsassociated with MarkWest Energy Partners’ March 28, 2003 credit facilityamendment offset a decrease in the average amount of debt outstanding in 2003.

 

*Write-down ofdeferred financing costs.*We wrote off $0.7 million in deferred financing costs in the first quarter of2002 as a result of amending our credit facility in March 2002.

 

*Minority interest in net income of consolidated subsidiary.*This represents theminority interest (i.e., non-MarkWest Hydrocarbon) ownership in the net incomeof MarkWest Energy Partners, which completed its initial public offering in May2002.

 

*Cumulativeeffect of change in accounting for asset retirement obligations.*We adopted SFAS No. 143, *Asset RetirementObligations*, in the first quarter of 2003.

 

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**Liquidity and Capital Resources**

 

MarkWest Hydrocarbon’s primary sources of liquidityare cash flow generated from operations and borrowings under our creditfacility. From time to time, our sources of funds are supplemented withproceeds from sales of assets and operating leases used to finance supportequipment. In 2002, we supplemented these sources through the IPO of MarkWestEnergy Partners, L.P. (net proceeds of $43 million, which was primarily used topay down our debt), and the sale of 500,000 subordinated units we owned in thePartnership (net proceeds of $8 million).

 

MarkWest Hydrocarbon’s cash flow generated fromoperations is subject to volatility in energy prices, especially prices forNGLs and natural gas. Our cash flow is enhanced in periods when the pricesreceived for NGLs are high relative to the price of natural gas we purchase tosatisfy our “keep-whole” contractual arrangements in Appalachia, and is reducedin periods when the prices received for NGLs are low relative to the price ofnatural gas we purchase to satisfy such contractual arrangements. Under“keep-whole” contracts, we retain and sell the NGLs produced in our processingoperations for third-party producers, and then reimburse or “keep whole” theproducers for the Btu content of the NGLs removed through the re-delivery tothe producers of an equivalent amount (on a Btu basis) of dry natural gas.  Generally, the value of the NGLs extractedis greater than the cost of replacing those Btus with dry gas, resulting inpositive operating margins under these contracts. Periodically, when natural gasbecomes more expensive, on a Btu equivalent basis, than NGL products, the costof keeping the producer “whole” can result in operating losses.

 

Toward the end of the first quarter of 2003, naturalgas prices began to be unusually high compared to NGL prices. This trend isforecast to continue through at least the second quarter of 2003.  This unusual disparity in prices has reducedour internally generated cash flows, will likely cause limitations on theavailability of borrowings under our credit facility, and may cause us to be innoncompliance with certain financial covenants under the credit facility.

 

We have commenceddiscussions with the lenders under our credit facility and believe that we willbe able to obtain covenant waivers should noncompliance occur. However, webelieve that during any period of noncompliance, borrowings under the creditfacility would be limited to amounts currently available, exclusive of MarkWestEnergy Partners’ credit facility (discussed below). As of March 31, 2003,MarkWest Hydrocarbon has borrowed $44.7 million of the $52.9 millionavailable credit under our $60 million credit facility.

 

In light of theforecasted reduction in cash flows and possible limits on available borrowingsunder our credit facility, MarkWest Hydrocarbon has undertaken a series of initiativesto enhance our liquidity position and to take advantage of favorable marketvaluations of domestic exploration and production assets.  Accordingly, we have engaged a third partyto act as financial advisor to MarkWest Hydrocarbon to assist in solicitingacquisition proposals for certain of our developed oil and gas properties. Theexpected sale proceeds from these properties would substantially improve ourliquidity and allow us to maintain full compliance with our credit facilitycovenants.

 

Almost all of our capitalexpenditures are discretionary.  We willtherefore manage our future capital expenditures to match available cash flowsfrom operations.

 

For MarkWest EnergyPartners, future acquisitions or projects are expected to be financed through acombination of debt and issuance of additional units, as is common practicewith master limited partnerships. The March 2003 Pinnacle acquisition wasfinanced under MarkWest Energy Partners’ credit facility, which was expanded by$15 million on March 28, 2003.  As ofMarch 31, 2003, MarkWest Energy Partners has borrowed $61.1 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$17 million for 2003, almost all of which is for discretionary explorationand production projects. The capital budget may change contingent upon a numberof factors, including results of operations and cash flow.

 

15

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*Cash Flows*

 

Netcash provided by operating activities was $9.5 million and $19.1 millionfor the three months ended March 31, 2003 and 2002, respectively. Net cashprovided by operating activities decreased during the first three months of 2003due to lower volumes and higher natural gas prices.

 

Netcash used in investing activities was $44.9 million and $9.1 million forthe three months ended March 31, 2003 and 2002, respectively. Net cashused in investing activities was larger in 2003 due to our Pinnacleacquisition.

 

Net cash provided by financingactivities was $36.8 million during the first three months of 2003.  Net cash used in financing activities was$12.0 million during the first three months of 2002.  In 2003, we had net borrowings as we financed our Pinnacleacquisition.  During 2002, we completedour seasonal conversion of inventories to cash, which we used to pay downlong-term debt.

 

##### **Outlook**

 

Weexpect natural gas prices to remain high for several months, which may continueto adversely affect our overall cash flow from operations if there continues tobe a significant negative disparity between natural gas prices and NGL productprices.

 

MarkWest Energy Partners’ Appalachian plants were shutdown during April and early May for annual maintenance.  The shut down period varied by plant andlasted between a few days to two to three weeks.  Consequently, second quarter 2003 Appalachian throughput volumeswill decrease relative to the first quarter of 2003.  However, the resulting volumetric decrease in cash flow fromAppalachian operations should be more than offset by cash flow from MarkWestEnergy Partners’ Texas (Pinnacle) operations, which began contributing to ourconsolidated results March 28, 2003.

 

Weexpect our second quarter 2003 natural gas production to decline compared toour first quarter 2003 production levels. In the San Juan Basin, a third-party pipeline shut down for maintenancewill shut down our production for approximately a week.

 

# ***Item 3.  Quantitative and Qualitative Disclosures about Market Risk***

 

***Commodity PriceRisk***

 

*Overview*

 

Our business bothproduces 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 commoditiesthat subject us to price risk. Commodity prices are often subject to material changes in response torelatively minor changes in supply and demand, general economic conditions andother market conditions over which we have no control, like the weather.

 

Our primary riskmanagement objective is to manage our price risk, thereby reducing volatilityin our cash flows.  Our hedging approachuses 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 mayincrease with capital commitments and debt levels and when above-average marginsexist.  We maintain a committee, includingmembers of senior management, which oversees all hedging activity.

 

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

 

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We enter OTC swaps withcounterparties that are primarily financial institutions. We use standardizedswap agreements that allow for offset of positive and negative exposures.  Net credit exposure is marked to marketdaily.  We are subject to margin depositrequirements under OTC agreements (with non-bank counterparties) and NYMEXpositions.

 

The use of financialinstruments may expose us to the risk of financial loss in certaincircumstances, including instances when (i) sales volumes may be less thanexpected requiring market purchases to meet commitments, (ii) our OTCcounterparties could fail to purchase or deliver the contracted quantities ofnatural gas, NGL, or crude oil or otherwise fail to perform, and (iii) when thetrading relationship between crude oil and NGL products is outside historicallevels.  To the extent that we engage inhedging activities, we may be prevented from realizing the benefits of favorableprice changes in the physical market. However, we may be similarly insulated against decreases in such prices.

 

*Types of Price Risk*

 

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

 

•                  Under“keep-whole” contracts, we take title to and sell the NGLs produced in ourprocessing operations. We also reimburse or “keep whole” the producers for theBtu content of the NGLs removed through the re-delivery to the producers of anequivalent amount (on a Btu basis) of dry natural gas.  Keep-whole contracts therefore expose us toNGL product price risk (on the sales side) and natural gas price risk (on thepurchase or reimbursement side). Generally, the value of the NGLs extracted is greater than the cost ofreplacing those Btus with dry gas, resulting in positive operating marginsunder these contracts. In the event natural gas becomes more expensive, on aBtu 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 ofnatural gas with an equivalent Btu content is called the “frac spread”.

 

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

 

Our fully consolidatedsubsidiary, MarkWest Energy Partners, is also subject to NGL price riskstemming from its percent-of-proceeds contracts (representing approximately 15%of its gross margin prior to the Pinnacle acquisition) and natural gas pricerisk from its recent Pinnacle acquisition. MarkWest Energy Partners gathers and transports natural gas forproducers behind our gathering systems in Texas, many under percent-of-proceedsor percent-of-index contracts.  Underthese contracts MarkWest Energy Partners is entitled to approximately 10% ofthe natural gas produced.

 

*Basis Risk*

 

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

 

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

 

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As of March 31, 2003, ournatural gas basis hedges were as follows:

 
|      |   | **Table  I  Hedged Natural Gas Basis** |   |
|-----------|--------|----------------------------------------|--------|
|      |   | **Year  Ending  December 31, 2003**    |   |
| MMBtu     |   | 2,996,000                              |   |
| $  /MMBtu |   | $                                      | (0.42  | ) |
|           |        |                                        |        |  |

 

We are generally unableto hedge our basis risk for NGL products. We have two different types of NGL product basis risk.  First, NGL product basis risk stems from thegeographic price differentials between our sales locations and hedging contractdelivery locations.  We cannot hedge ourgeographic basis risk because there are no readily available products ormarkets.  Second, NGL product basis riskalso results from the difference in relative price movements between crude oiland NGL products.  We may use crude oil,instead of NGL products, in our hedges because the NGL hedge products andmarkets are limited.  Crude oil ishighly correlated with certain NGL products.

 

*Natural Gas Price Risk*

 

Generally, we are anoverall net consumer of natural gas as our keep-whole contractual requirementsfor purchasing natural gas in Appalachia currently exceed our natural gasproduction.  Until such time thisrelationship reverses and we become a net producer of natural gas, our E&Phedges are generally limited to either (i) obtaining futures prices that ourmodels suggest are optimal, (ii) realizing the economics of a transaction, likeour 2001 Canadian E&P acquisition, or (iii) mitigating our basis risk asdescribed above.  Generally, we executeour strategy by either entering into fixed-for-float swaps or utilizingcostless collars.  As of March 31, 2003,we have hedged our combined Canadian and Rocky Mountain natural gas volumes andprices as follows:

 
|                              |   | **Table II  Hedged Natural Gas Sales** |   |
|-----------------------------------|--------|----------------------------------------|--------|
|                              |   | **Year  Ending December 31,**          |   |
|                              |   | **2003**                               |   | **2004** |   | **2005** |   |
|                              |   |                                   |   |   |   |   |   |
| MMBtu                             |   | 3,527,000                              |   | 2,877,000 |   | 44,100 |   |
| $  /MMBtu                         |   | $                                      | 3.40   |   | $ | 3.30 |   | $ | 3.34 |   |
| Henry  Hub Equivalent $/MMBtu (1) |   | $                                      | 4.02   |   | $ | 3.88 |   | $ | 3.81 |   |

 

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(1) Reflects our hedgednatural gas prices as if natural gas was sold at Henry Hub (NYMEX).

 

Regardingour natural gas price risk in Texas (part of our Pinnacle acquisition), weenter into fixed-for-float swaps or buy puts. As of March 31, 2003, no such hedges were in place.  As of May 6, 2003, we had hedged our Texasnatural gas price risk via swaps as follows:

 
|     |   | **Table III  Hedged Natural Gas Sales** |   |
|----------|--------|-----------------------------------------|--------|
|     |   | **Year  Ending December 31,**           |   |
|     |   | **2003**                                |   | **2004** |   | **2005** |   |
|     |   |                                    |   |   |   |   |   |
| MMBtu    |   | 122,500                                 |   | 183,000 |   | 182,500 |   |
| $ /MMBtu |   | $                                       | 5.09   |   | $ | 4.57 |   | $ | 4.26 |   |
|          |        |                                         |        |  |  |  |  |  |  |  |

 

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Asof May 6, 2003, we had hedged our Texas natural gas price risk via puts asfollows:

 
|                    |   | **Table IV  Hedged Natural Gas Sales** |   |
|-------------------------|--------|----------------------------------------|--------|
|                    |   | **Year  Ending December 31,**          |   |
|                    |   | **2003**                               |   | **2004** |   | **2005** |   |
|                    |   |                                   |   |   |   |   |   |
| MMBtu                   |   | 245,000                                |   | 366,000 |   | — |   |
| Strike  price ($/MMBtu) |   | $                                      | 4.50   |   | $ | 4.00 |   | $ | 0.00 |   |
|                         |        |                                        |        |  |  |  |  |  |  |  |

 

*NGL Product Price Risk*

 

We hedge our NGL productsales by selling forward propane or crude oil. As of March 31, 2003, we have hedged Appalachian and NGL product salesas 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                        |   | 61,746,000                                       |   | 13,113,000 |   |
| NGL  sales prices per gallon        |   | $                                                | 0.38   |   | $ | 0.51 |   |
|                                |   |                                             |   |   |   |
| **MarkWest  Energy Partners, L.P.** |   |                                             |   |   |   |
| NGL  Volumes Hedged Using Crude Oil |   |                                             |   |   |   |
| NGL  gallons                        |   | 2,862,000                                        |   | — |   |
| NGL  sales price per gallon         |   | $                                                | 0.46   |   | — |   |
| NGL  Volumes Hedged Using Propane   |   |                                             |   |   |   |
| NGL  gallons                        |   | 1,008,000                                        |   | — |   |
| NGL  sales price per gallon         |   | $                                                | 0.41   |   | — |   |
| Total  NGL Volumes Hedged           |   |                                             |   |   |   |
| NGL  gallons                        |   | 3,870,000                                        |   | — |   |
| NGL  sales price per gallon         |   | $                                                | 0.44   |   | — |   |
|                                     |        |                                                  |        |  |  |  |  |

 

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

 

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

 

To the extent our Appalachian natural gas purchaserequirements exceed our E&P natural gas production, we are simultaneouslysubject to NGL price risk on the sales side and natural gas price risk on thepurchase side within our GPM business.  Consequently, we may hedge our Appalachian processing margin (defined asrevenues less purchased product costs) by simultaneously selling propane orcrude oil while purchasing natural gas. However, as of March 31, 2003, we had no such hedges in place.

 

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##### **Item 4. Controls and Procedures**

 

Basedon their evaluation of the internal controls, disclosure controls andprocedures within 90 days of the filing date of this report, the ChiefExecutive Officer and the Chief Financial Officer have concluded that theeffectiveness of such controls and procedures is satisfactory. Further therewere not any significant changes in our internal controls or in other factorsthat could significantly affect these controls subsequent to the date of theirevaluation.

 

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##### **PART II—OTHER INFORMATION**

 

##### **Item 1.  Legal Proceedings**

 

Reference is made to Note 8 of our ConsolidatedFinancial Statements in Item 1 of this Form 10-Q.

 

**Item 6.  Exhibits and Reports on Form 8-K**

 

(a)   Exhibits

 

99.1*Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, asAdopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

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

 

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*Filed herewith.

 

(b)   Reports on Form 8-K

 

A report on Form 8-K wasfiled on March 26, 2003, announcing that MarkWest Hydrocarbon’s46.7 percent-owned affiliate, MarkWest Energy Partners, L.P., has enteredinto a Purchase and Sale Agreement with Energy Spectrum Partners, L.P., for theacquisition of Pinnacle Natural Gas Company and certain affiliates forapproximately $38 million.

 

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**SIGNATURE**

 

Pursuant to therequirements of the Securities Exchange Act of 1934, MarkWest Hydrocarbon, asregistrant, has duly caused this report to be signed on its behalf by theundersigned, thereunto authorized.

 

MarkWest Hydrocarbon, Inc.

(Registrant)

 
| Date:  | May 14, 2003 |   |   |   |   |   |   |   | /s/ Donald C.  Heppermann                                               |   |
|--------|--------------|--------|--------|--------|--------|--------|--------|--------|-------------------------------------------------------------------------|--------|
|   |         |   |   |   |   |   |   |   |                                                                    |   |
|   |         |   |   |   |   |   |   |   | Donald C. Heppermann                                                    |   |
|   |         |   |   |   |   |   |   |   | Senior Vice President  Finance,  Chief Financial Officer and  Secretary |   |

 

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**CERTIFICATION**

 

I, John M. Fox, certifythat:

 

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

 

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

 

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

 

4. The registrant’s othercertifying officer and I are responsible for establishing and maintainingdisclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and15d-14) for the registrant and we have:

 

a) Designed suchdisclosure controls and procedures to ensure that material information relatingto the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which thisquarterly report is being prepared.

 

b) Evaluated theeffectiveness of the registrant’s disclosure controls and procedures as of adate within 90 days prior to the filing date of this quarterly report (the“Evaluation Date”).

 

c) Presented in thisquarterly report our conclusions about the effectiveness of the disclosurecontrols and procedures based on our evaluation as of the Evaluation Date.

 

5. The registrant’s othercertifying officers and I have disclosed, based on our most recent evaluation,to the registrant’s auditors and the audit committee of registrant’s board ofdirectors (or persons performing the equivalent function):

 

a) All significant deficienciesin the design or operation of internal controls which could adversely affectthe registrant’s ability to record, process, summarize and report financialdata and have identified for the registrant’s auditors any material weaknessesin internal controls.

 

b) Any fraud, whether ornot material, that involves management or other employees who have asignificant role in the registrant’s internal controls.

 

6. The registrant’s othercertifying officers and I have indicated in this quarterly report whether ornot there were significant changes in internal controls or in other factorsthat could significantly affect internal controls subsequent to the date of ourmost recent evaluation, including any corrective actions with regard tosignificant deficiencies and material weaknesses.

 
| Date:  | May 14, 2003 |   |   |   |   |   |                                    |   |   |
|--------|--------------|--------|--------|--------|--------|--------|-----------------------------------------|--------|--------|
|   |         |   |   |   |   |   |  /s/ John M. Fox                   |   |
|   |         |   |   |   |   |   | John M. Fox                             |   |
|   |         |   |   |   |   |   | President and Chief  Executive  Officer |

 

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**CERTIFICATION**

I, Donald C. Heppermann,certify that:

 

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

 

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

 

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

 

4. The registrant’s othercertifying officer and I are responsible for establishing and maintainingdisclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and15d-14) for the registrant and we have:

 

a) Designed suchdisclosure controls and procedures to ensure that material information relatingto the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which thisquarterly report is being prepared.

 

b) Evaluated theeffectiveness of the registrant’s disclosure controls and procedures as of adate within 90 days prior to the filing date of this quarterly report (the“Evaluation Date”).

 

c) Presented in thisquarterly report our conclusions about the effectiveness of the disclosurecontrols and procedures based on our evaluation as of the Evaluation Date.

 

5. The registrant’s othercertifying officers and I have disclosed, based on our most recent evaluation,to the registrant’s auditors and the audit committee of registrant’s board ofdirectors (or persons performing the equivalent function):

 

a) All significantdeficiencies in the design or operation of internal controls which couldadversely affect the registrant’s ability to record, process, summarize andreport financial data and have identified for the registrant’s auditors anymaterial weaknesses in internal controls.

 

b) Any fraud, whether ornot material, that involves management or other employees who have asignificant role in the registrant’s internal controls.

 

6. The registrant’s othercertifying officers and I have indicated in this quarterly report whether ornot there were significant changes in internal controls or in other factorsthat could significantly affect internal controls subsequent to the date of ourmost recent evaluation, including any corrective actions with regard tosignificant deficiencies and material weaknesses.

 
| Date:  | May 14, 2003 |   |                                                                    |   |
|--------|--------------|--------|-------------------------------------------------------------------------|--------|
|   |         |   | /s/ Donald C.  Heppermann                                               |   |
|   |         |   |                                                                    |   |
|   |         |   | Donald C. Heppermann                                                    |   |
|   |         |   | Senior Vice President  Finance,  Chief Financial Officer and  Secretary |

 

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