**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C.20549**

 

**FORM 10-Q**

 

| **ý**                                       | **Q****UARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)  OF THE SECURITIES EXCHANGE ACT OF 1934** |
|--------------------------------------------------|--------------------------------------------------------------------------------------------------|
|                                             |
| **For the quarterly period ended June 30, 2003** |
|                                             |
| **OR**                                           |
|                                             |
| **o**                                            | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**     |
|                                                  |                                                                                                  |  |

 

**For the transitionperiodfrom              to               **

 

**Commission FileNumber 1-11566**

 

| **MARKWEST HYDROCARBON, 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 mark whetherthe registrant (1) has filed all reports required to be filed by Section 13 or15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (orfor such shorter period that the registrant was required to file such reports),and (2) has been subject to such filing requirements for the past 90 days.

Yes   ý        No   o

 

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

Yes   o        No   ý

 

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

 

 

----

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

 

#### **Glossary of Terms**

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

 

----

 

**PART 1–FINANCIALINFORMATION**

**Item 1.   Consolidated Financial Statements**

** **

**MARKWEST HYDROCARBON,INC.**

**CONSOLIDATED BALANCE SHEETS**

**(UNAUDITED)**

**(In thousands,excepts share and per share data)**

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

 

The accompanying notes are an integral part of these financialstatements.

 

1

----

 

**MARKWEST HYDROCARBON,INC.**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS**

**(UNAUDITED)**

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

 

The accompanying notes are an integral part of these financialstatements.

 

2

----

** **

**MARKWEST HYDROCARBON,INC.**

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**

**(UNAUDITED)**

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

** **

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

 

3

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**MARKWEST HYDROCARBON,INC.**

**CONSOLIDATEDSTATEMENTS OF CHANGES IN******

**STOCKHOLDERS’ EQUITY**

**(UNAUDITED)**

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

 

The accompanying notes are an integral part of these financialstatements.

 

4

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**MARKWEST HYDROCARBON, INC**

**NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS**

** **

**1.****              General**

 

The consolidated financial statements include the accountsof MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon”), and its consolidatedsubsidiaries. 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 year-endbalance sheet data was derived from audited financial statements but does notinclude all disclosures required by accounting principles generally accepted inthe United States. Please read the interim consolidated financial statements inconjunction with the Consolidated Financial Statements and attached notes forthe year ended December 31, 2002, included in our Annual Report on Form 10-K,as filed with the Securities and Exchange Commission. In the opinion ofmanagement, we have made all necessary normal recurring adjustments for a fairstatement of the results for the unaudited interim periods.

 

We base the effective corporate tax rate for interim periodson the estimated annual effective corporate tax rate. The effective tax ratevaries from statutory rates primarily due to permanent differences in Canadaand percentage depletion in excess of basis in the U.S.

 

**2.****              Sale of San JuanBasin Properties**

 

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

 

**3.****              PinnacleAcquisition**

 

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

 

The Pinnacle 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 andliabilities of the Sellers were allocated to the MarkWest Energy Partnersentities, and all entities survived the merger. The assets acquired from theSellers, primarily located in the state of Texas, with the balance located inNew Mexico, Louisiana, Mississippi and Kansas, are comprised of three lateralnatural gas pipelines and twenty gathering systems.

 

The purchase price was allocated asfollows (in thousands):

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

 

5

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*ProForma Results of Operations (Unaudited)*

 

Thefollowing table reflects the unaudited pro forma consolidated results ofoperations for the three and six months ended June 30, 2003 and 2002, as thoughthe Pinnacle Acquisition had occurred on January 1, 2002. These unaudited proforma results have been prepared for comparative purposes only and are notnecessarily indicative of future results.

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

 

**4.****              Private Placement**

 

Our consolidated subsidiary, MarkWest Energy Partners, sold375,000 common units in two installments at a price of $26.23 per unit in aprivate placement to certain accredited investors. The first installment of300,031 units was completed on June 27, 2003, and grossed approximately $7.9million. The second installment of 74,969 units was completed on July 10, 2003,and grossed approximately $1.9 million. MarkWest Energy Partners’ generalpartner paid its pro rata contribution in July 2003 after the secondinstallment was completed. MarkWest Energy Partners primarily used the proceedsto pay down debt under its credit facility.

 

**5.****              Related PartyTransactions**

 

*MarkWest Hydrocarbon, Inc.*

 

Through our whollyowned subsidiary, MarkWest Resources, Inc. (“Resources”), we held variedundivided interests in several exploration and production assets in which MAK-JEnergy Partners Ltd. (“MAK-J”) also owns an undivided interest, varying from25% to 51%. The general partner of MAK-J is a corporation owned and controlledby our President and Chief Executive Officer. One current officer and oneformer officer, who left the Company on July 31, 2003, are limited partners inMAK-J. Joint property acquisitions and joint operating agreements are subjectto the approval of independent members of our Board of Directors. Theproperties were operated pursuant to joint operating agreements entered into betweenResources and MAK-J. Resources was the operator under such agreements. Thejoint operating agreements are governed by a Participation and OperationsAgreement, most recently amended June 2, 2003. As the operator, Resources wasobligated to provide certain accounting and well operations services to theparties. The Participation and Operations Agreement provided for a monthly fee($2,000 per month) payable to Resources to offset the costs of accounting andwell operations on a monthly basis. As a part of the sale of oil and gasproperties to XTO Energy on June 30, 2003, the Participation and OperationsAgreement was assigned to XTO Energy.

 

Through our whollyowned subsidiary, Matrex, LLC, we hold interests in certain exploration andproduction assets in which MAK-J also owns interests.  Both parties are participants to joint operating agreementsinvolving other third parties.

 

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

 

6

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

 

*MarkWest Energy Partners*

 

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

 

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

 

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

 

**6.****              Dispositions**

 

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

 

**7.****              Segment Reporting**

 

Our operations areclassified into three reportable segments:

 

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

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

(3)          Marketing—sellour equity and third party NGLs and purchase and market third-party naturalgas.

 

OnMay 24, 2002, we spun off our gathering and processing assets into MarkWestEnergy Partners, our fully consolidated subsidiary. The formation and initialpublic offering (the “IPO”) of MarkWest Energy Partners (the IPO closed on May24, 2002) and the subsequent change to the structure of our internalorganization caused the composition of our reportable segments to change in thefourth quarter of 2002. Prior to the fourth quarter of 2002, we classified ouroperations into two reportable segments:

 

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

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

 

Although thethree and six months ended June 30, 2003 reflects our new segments, informationprior to May 24, 2002, has not been restated to reflect the change insegmentation 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 such arrangement existed prior to the formationof MarkWest 

 

7

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Energy Partners. As a result, it is notpracticable to restate certain prior period segment information to conform toour current presentation.

 

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

 

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

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

 
|                                 |   | **Exploration  and Production** |   | **Gathering   Processing &**

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

 

8

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

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

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

 

9

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**8.****              Commitments andContingencies**

 

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

 

**9.****              Stock and UnitCompensation**

 

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

 

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

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

 

Compensationexpense for the variable plan, including restricted unit grants, is measuredusing the market price of MarkWest Energy Partners’ common units on the lasttrading day of the corresponding quarter and is amortized into earnings overthe period of service. Our stock options are issued under a fixed plan.Accordingly, compensation expense is not recognized for stock options unlessthe options were granted at an exercise price lower than market on the grantdate

 

**10.****      ****Asset RetirementObligations**

 

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 will beallocated to expense using a systematic and rational method. During the first quarterof 2003, we recorded a net-of-tax cumulative effect of change in accountingprinciple charge of $29,000 ($63,000 before tax), an asset retirementobligation of $3.4 million (a net increase to long-term liabilities of $2.5million). We also increased net properties $2.4 million in accordance with theprovisions of SFAS No. 143. There was no impact on our cash flows as a resultof adopting SFAS No. 143. The pro forma asset retirement obligation would havebeen $2.5 million at January 1, 2002 had we adopted SFAS No. 143 on January 1,2002. The asset retirement obligation, which is included on the ConsolidatedBalance Sheet in Other Long-Term Liabilities, was $3.3 million at June 30,2003.

 

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

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

 

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

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

 

**11.****       Recent AccountingPronouncements**

 

Statement ofFinancial Accounting Standards No. 141, *BusinessCombinations* (“FAS 141”) and Statement of Financial AccountingStandards, No. 142*, Goodwill and IntangibleAssets* (“FAS 142”) were issued by the Financial Accounting StandardsBoard (“FASB”) in June 2001 and became effective for us on July 1, 2001 andJanuary 1, 2002, respectively.  FAS 141requires all business combinations initiated after June 30, 2001 to beaccounted for using the purchase method. Additionally, FAS 141 requires companies to disaggregate and reportseparately from goodwill certain intangible assets.  FAS 142 establishes new guidelines for accounting for goodwilland other intangible assets.  Under FAS142, goodwill and certain other intangible assets are not amortized, but ratherare reviewed annually for impairment. The FASB, the Securities and Exchange Commission (“SEC”) and otherscontinue to discuss the appropriate application of FAS 141 and 142 to oil andgas mineral rights held under lease and other contractual arrangementsrepresenting the right to extract such reserves.  Depending on the outcome of such discussions, these oil and gasmineral rights held under lease and other contractual arrangements representingthe right to extract such reserves for both undeveloped and developedleaseholds may be classified separately from oil and gas properties, asintangible assets on our balance sheets. In addition, the disclosures required by FAS 141 and 142 relative tointangibles would be included in the notes to financial statements.  Historically, we, like many other oil andgas companies, have included these oil and gas mineral rights held under leaseand other contractual arrangements representing the right to extract suchreserves as part of the oil and gas properties, even after FAS 141 and 142became effective.

 

As applied tocompanies like us that have adopted full cost accounting for oil and gasactivities, we understand that this interpretation of FAS 141 and 142 wouldonly affect our balance sheet classification of proved oil and gas leaseholdsacquired after June 30, 2001 and our unproved oil and gas leaseholds.  Our results of operations and cash flowswould not be affected, since these oil and gas mineral rights held under leaseand other contractual arrangements representing the right to extract suchreserves would continue to be amortized in accordance with full cost accountingrules.

 

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

 

We willcontinue to classify our oil and gas mineral rights held under lease and othercontractual rights representing the right to extract such reserves as tangibleoil and gas properties until further guidance is provided.

 

11

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**12.****      ****Subsequent Events**

 

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

 

On July 31, 2003, MarkWest Hydrocarbon’s consolidatedsubsidiary, MarkWest Energy Partners, entered into a Purchase and SaleAgreement to purchase a 68-mile intrastate gas transmission pipeline nearLubbock, Texas for approximately $12 million. The transaction is expected toclose on September 1, 2003, and it will be financed through its existing creditline.

 

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

 

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##### **Item 2.   Management’s Discussion and Analysis ofFinancial Condition and Results of Operations**

 

**Forward-LookingInformation**

 

Statementsincluded in this Management’s Discussion and Analysis that are not historicalfacts are forward-looking statements within the meaning of Section 27A of theSecurities Act of 1933, as amended, and Section 21E of the Securities andExchange Act of 1934, as amended. We use words such as “may,” “believe,”“estimate,” “expect,” “plan,” “intend,” “project,” “anticipate,” and similarexpressions to identify forward-looking statements. We have based theseforward-looking statements on our current expectations and projections aboutfuture events, activities or developments. Our actual results could differmaterially from those discussed in our forward-looking statements.  Forward-looking statements includestatements 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

 

Importantfactors that could cause our actual results of operations or our actualfinancial condition to 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 to control.In many cases, we cannot predict what factors would cause actual results todiffer materially from those indicated by the forward-looking statements.

 

13

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**Saleof San Juan Basin Properties**

 

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

 

**PinnacleAcquisition**

 

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

 

Theacquisition was accomplished through a merger under Texas law of the Sellersand four newly formed wholly owned subsidiaries of MarkWest Energy Partners asbuyers. 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 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 lateral natural gas pipelines consist ofapproximately 67 miles of pipe and transport up to 1.1 Bcf/day under firmcontracts to power plants. The twenty gathering systems gather more than 44MMcf/d.

 

##### **Extended Facility Maintenance**

 

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

 

**Results of Operations**

 

*Operating Data*

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

*** ***

----

***NM –Not meaningful***

(1)  Acquired March28, 2003, our MarkWest Pinnacle assets are located primarily in Texas and foursurrounding states.

 

14

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

## ** **

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

 

*Gathering,processing and marketing revenue.* Gathering,processing and marketing revenue was $47.9 million for the three months endedJune 30, 2003 compared to $38.6 million for the three months ended June30, 2002, an increase of $9.3 million, or 24%. The Pinnacle Acquisitionincreased revenues $16.7 million, partially offset by a reduction in gasmarketing revenues of $8.3 million, a result of reduced volumes sold. Increasedprices in our Appalachian percent-of-proceeds contract business and increasedprices and throughput and sales volumes in our Michigan operations increasedrevenues $1.1 million.

 

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

 

*Purchased productcosts.* Purchased product costs were $44.4 million for the three months endedJune 30, 2003, compared to $32.3 million for the three months ended June30, 2002, an increase of $12.1 million, or 38%. The Pinnacle Acquisitionincreased purchased product costs $13.7 million, partially offset by areduction in gas marketing purchased products costs of $7.3 million, a resultof reduced volumes sold. Higher natural gas prices in our keep-whole contractbased business increased purchased product costs $6.3 million.

 

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

 

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

 

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

 

*Production taxes. *Production taxes were $0.6 millionfor the three months ended June 30, 2003, compared to $0.5 million for thethree months ended June 30, 2002, an increase of $0.1 million, or 24%.Production taxes increased principally due to increased natural gas prices in2003.

 

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

 

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

 

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

 

15

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*Write-down of deferred financing costs.*We wrote off $2.3 million in deferred financing costs in the second quarter of2002 as a result of amending our credit facility in the second quarter of 2002.

 

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

 

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

## ** **

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

 

*Gathering,processing and marketing revenue.* Gathering,processing and marketing revenue was $98.5 million for the six months endedJune 30, 2003 compared to $75.9 million for the six months ended June 30,2002, an increase of $22.6 million, or 30%. Revenue was higher in 2003 than in2002 primarily due to:

 

•                  The PinnacleAcquisition added $17.5 million.

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

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

 

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

 

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

 

•                  The PinnacleAcquisition added $14.4 million.

•                  Increasednatural gas costs offset volume decreases in Appalachia adding $21.8 million inpurchased product costs.

•                  Gas marketingvolumes declined primarily due to reduced volumes sold decreasing purchasedproduct costs $6.5 million.

 

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

 

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

 

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

 

*Production taxes. *Production taxes were $1.3 millionfor the six months ended June 30, 2003, compared to $0.8 million for thesix months ended June 30, 2002, an increase of $0.6 million, or 42%.Production taxes increased principally due to increased natural gas prices in2003.

 

16

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*Selling,*g*eneral andadministrative expenses.* Selling, general and administrative expenses were $6.8 million for thesix months ended June 30, 2003, compared to $5.6 million for the six monthsended June 30, 2002, an increase of $1.2 million, or 22%. The increase isprincipally attributable to increased insurance costs and incremental costs associatedwith operating MarkWest Energy Partners as a public company.

 

*Depreciation and depletion.*Depreciation and depletion were $11.1 million for the six months endedJune 30, 2003, compared to $10.1 million, for the six months ended June30, 2002, an increase of $1.0 million, or 10%. Depreciation and depletionincreased due to the Pinnacle Acquisition and a mid-year revision of ourCanadian reserves.

 

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

 

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

 

*Minority interest in net income ofconsolidated subsidiary.*This represents the minorityinterest (i.e., non-MarkWest Hydrocarbon) ownership in the net income ofMarkWest 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 Retirement Obligations*, in thesecond quarter of 2003.

 

**Liquidity and CapitalResources**

 

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

 

MarkWest Hydrocarbon’s cash flow generated from operationsis subject to volatility in energy prices, especially prices for NGLs andnatural gas. Our cash flow is enhanced in periods when the prices received forNGLs are high relative to the price of natural gas we purchase to satisfy our“keep-whole” contractual arrangements in Appalachia, and is reduced in periodswhen the prices received for NGLs are low relative to the price of natural gaswe purchase to satisfy such contractual arrangements. Under “keep-whole”contracts, we retain and sell the NGLs produced in our processing operationsfor third-party producers, and then reimburse or “keep whole” the producers forthe Btu content of the NGLs removed through the re-delivery to the producers ofan equivalent amount (on a Btu basis) of dry natural gas. Generally, the valueof the NGLs extracted is greater than the cost of replacing those Btus with drygas, resulting in positive operating margins under these contracts.Periodically, when natural gas becomes more expensive, on a Btu equivalentbasis, than NGL products, the cost of keeping the producer “whole” can resultin operating losses.

 

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

 

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

 

17

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Almostall of our capital expenditures are discretionary.  We continue to manage our future capital expenditures to matchavailable cash flows from operations. As of June 30, 2003, MarkWest Hydrocarbonhas borrowed $24.8 million of the approximate $26.8 million availablecredit under our credit facility. As of July 1, 2003, we paid down anadditional $11.4 million on our credit facility.

 

For MarkWestEnergy Partners, future acquisitions or projects are expected to be financedthrough a combination of debt and issuance of additional units, as is commonpractice with master limited partnerships. The March 2003 Pinnacle acquisitionwas financed under MarkWest Energy Partners’ credit facility, which wasexpanded by $15 million on March 28, 2003. Additionally, MarkWest EnergyPartners sold 375,000 common units in two installments at a price of $26.23 perunit in a private placement to certain accredited investors. These salesgrossed $9.8 million and were completed July 10, 2003. As of June 30, 2003,MarkWest Energy Partners has borrowed $55.1 million of the $75 millionavailable credit under its $75 million credit facility.

 

MarkWestHydrocarbon (exclusive of MarkWest Energy Partners) forecasts a baselinecapital budget of $11.4 million for 2003, almost all of which is fordiscretionary exploration and production projects. The capital budget maychange contingent upon a number of factors, including results of operations andcash flow and availability under our credit facility.

 

*CashFlows*

 

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

 

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

 

Net cash provided by financingactivities was $15.7 million during the first six months of 2003. Net cash usedin financing activities was $13.1 million during the first six months of2002.  In 2003, we had net borrowings,primarily due to the financing of the Pinnacle Acquisition. Additionally,MarkWest Energy Partners, our consolidated subsidiary, raised capital via aprivate placement of 375,000 of its common units. During 2002, we completed ourseasonal conversion of inventories to cash, which we used to pay down long-termdebt.

# *** ***

# ***Item 3.   Quantitative and QualitativeDisclosures about Market Risk***

 

***CommodityPrice Risk***

 

*Overview*

 

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

 

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

 

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

 

18

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

 

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

 

*Typesof Price Risk*

 

Withinour exploration and production segment, our revenues are subject to natural gasprice risk. Within our NGL marketing segment, our price risk varies by contractas 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 taketitle to and sell the NGLs produced in our processing operations. We alsoreimburse or “keep whole” the producers for the Btu content of the NGLs removedthrough the re-delivery to the producers of an equivalent amount (on a Btubasis) of dry natural gas. Keep-whole contracts therefore expose us to NGLproduct price risk (on the sales side) and natural gas price risk (on thepurchase or reimbursement side). Generally, the value of the NGLs extracted isgreater than the cost of replacing those Btus with dry gas, resulting inpositive operating margins under these contracts. In the event natural gasbecomes more expensive, on a Btu equivalent basis, than NGL products, the costof keeping the producer “whole” results in operating losses. The spread betweenthe NGL product sales price and the purchase price of natural gas with anequivalent 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 price risk.

 

Ourfully consolidated subsidiary, MarkWest Energy Partners, is also subject to NGLprice risk stemming from its percent-of-proceeds contracts in Appalachia andMichigan and natural gas price risk from the Pinnacle Acquisition. MarkWestEnergy Partners gathers and transports natural gas for producers behind itsgathering systems in Texas and four surrounding states, many underpercent-of-proceeds or percent-of-index contracts.

 

*BasisRisk*

 

Tothe extent our natural gas production equals our keep-whole requirements forpurchasing natural gas in Appalachia and there are no material differences innet prices, our commodity price risk is mitigated.

 

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

 

19

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

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

 

We aregenerally unable to hedge our basis risk for NGL products. We have twodifferent types of NGL product basis risk. First, NGL product basis risk stemsfrom the geographic price differentials between our sales locations and hedgingcontract delivery locations. We cannot hedge our geographic basis risk becausethere are no readily available products or markets. Second, NGL product basisrisk also results from the difference in relative price movements between crudeoil and NGL products. We may use crude oil, instead of NGL products, in ourhedges because the NGL hedge products and markets are limited. Crude oil ishighly correlated with certain NGL products.

 

*NaturalGas Price Risk*

 

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

 

Asof June 30, 2003, we have hedged our Canadian natural gas volumes and prices asfollows:

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

 

20

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

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

 

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

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

 

*NGLProduct Price Risk*

 

Wehedge our NGL product sales by selling forward propane or crude oil. As of June30, 2003, we have hedged NGL product sales, primarily in Appalachia, asfollows:

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

 

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

 

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Inaddition to these risk management tools, we utilize our NGL product storagefacilities and contracts for third-party storage to build product inventoriesduring lower-demand periods for resale during higher-demand periods.

 

To the extentour Appalachian natural gas purchase requirements exceed our E&P naturalgas production, we are simultaneously subject to NGL price risk on the salesside and natural gas price risk on the purchase 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 June 30, 2003, we had no such hedges in place.

 

***Interest Rate Risk***

 

*MarkWest Hydrocarbon, Inc.*

 

We are exposedto changes in interest rates, primarily as a result of our long-term debt withfloating interest rates. As of June 30, 2003, we were not a party to anyfinancial instruments to manage this risk.

 

*MarkWest Energy Partners, L.P.*

 

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

 

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

 

Pursuant to the requirements of the Securities and ExchangeCommission, we maintain disclosure controls and procedures that are designed toensure that information required to be disclosed by us in the reports that wefile or submit to the Commission under the Securities Exchange Act of 1934, asamended, is recorded, processed, summarized and reported within the timeperiods specified by the Commission’s rules and forms, and that information isaccumulated and communicated to our management, including our President andChief Executive Officer and our Senior Vice President Finance, Chief FinancialOfficer and Secretary (whom we refer to in this periodic report as ourCertifying Officers), as appropriate, to allow timely decisions regardingrequired disclosure.

 

In accordancewith Rule 13a-15(b) under the Exchange Act, our management evaluated theeffectiveness of our disclosure controls and procedures as of June 30, 2003.Based upon that evaluation, our Certifying Officers concluded that, as of June30, 2003, our disclosure controls and procedures were effective in all respectsexcept in alerting management that certain hedging transactions completed priorto February 2002 by MarkWest Resources, Inc., our wholly owned subsidiary thatwe refer to as Resources, were required to be reported by us as related partytransactions in our periodic reports filed with the Commission.

 

Through ourownership of Resources, we held until June 30, 2003 various undivided interestsranging from 25% to 51% in several exploration and production assets in whichMAK-J Energy Partners Ltd., or MAK-J, also owned an undivided interest. MAK-J’sgeneral partner is a corporation owned and controlled by our President andChief Executive Officer. Because these arrangements involved a related party,the joint property acquisitions and joint operating agreements betweenResources and MAK-J regarding the exploration and production assets werereviewed and approved by all of the independent members of our Board ofDirectors. The joint operating agreements provided that the revenues generatedfrom and costs associated with these jointly owned and operated properties wereshared pro rata in accordance with each party’s respective undivided ownershipinterest in such properties. Such agreements also provided that Resources hadthe discretion to enter into hedging transactions in respect of the properties.

 

Between August1999 and February 2002, Resources, under the oversight of our risk managementcommittee (which includes members of our senior management, but excludes ourPresident and Chief Executive Officer), entered into hedging transactions withrespect to these exploration and production assets on its own behalf, and onbehalf of MAK-J, in accordance with the joint operating agreements.

 

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

 

The failure ofResources to fully communicate to our appropriate SEC reporting and accountingpersonnel that Resources was entering into hedge agreements as agent for MAK-Jresulted in our failure to properly disclose those related party transactionsin our periodic reports filed with the Commission. It also resulted in ourfailure, since January 2001, when Statement of Financial Accounting StandardsNo. 133, “Accounting for Derivative Instruments and Hedging Activities,” wasadopted, to properly record in our financial statements the mark to marketadjustment related to the portion of the hedging transactions entered into onbehalf of MAK-J quarterly through earnings.

 

Our omissionof the MAK-J mark to market adjustments each quarter did not, however, have anymaterial financial impact in our consolidated financial statements for thoseperiods.  Had we properly recorded such thirdparty MAK-J adjustments, we would also have properly recorded an offsettinggain or loss, as applicable, on the hedge agreements between Resources andMAK-J.  Because Resources was acting asagent for MAK-J in respect of the hedging transactions, the gains and losses onthe third party derivative hedging transactions and the derivative hedgingtransactions between Resources and MAK-J would qualify for net reporting on ourconsolidated statement of operations for all applicable periods. Specifically,the financial statement impact would have been to record in each period themark to market adjustment on the third party contract as a derivative asset orliability with a corresponding offset to a payable to or receivable from MAK-J.Management of Resources has concluded that these adjustments to the previouslyissued consolidated financial statements are not material for restatement.

 

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

 

Notwithstandingthat the mark to market entry omission did not have a material financial impacton our financial statements, our independent auditor reported to us that theseweaknesses in our internal control over financial reporting constitutedmaterial weakness under Statement on Auditing Standards No. 60. A materialweakness under SAS No. 60 is a reportable condition in which thedesign or operation of one or more of the internal control components does notreduce to a relatively low level the risk that misstatements caused by error orfraud in amounts that would be material in relation to the financial statementsbeing audited may occur and not be detected within a timely period by employeesin the normal course of performing their assigned functions. To reduce thelikelihood that our hedging activity and related party disclosures may bemisreported in the future, our independent auditor recommended that we take,among others, the following measures:

 

•                  Establish aspecific written policy regarding related party hedging transactions;

•                  Involve to agreater degree accounting personnel in all hedging transactions;

•                  Require bypolicy that all hedging transactions be appropriately documented; and

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

 

Our auditcommittee decided to address the hedging disclosure omission by directing usnot to enter into any future related party hedging transactions and byimplementing enhanced procedures designed to identify any related partytransaction that might require disclosure.

 

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Because thesedeficiencies were identified after the completion of our second fiscal quarter,there were no changes in our internal control over financial reporting that occurredduring our most recently completed fiscal quarter that has materially affected,or is reasonably likely to materially affect, our internal control overfinancial reporting. Furthermore, because our audit committee has determined itto be in our best interests and in the best interests of our stockholders toprohibit us and our subsidiaries from engaging in any future related partyhedging transactions, and because all of our and Resources’ other hedgingactivities were properly recorded and disclosed, the audit committee determinedthat it did not need to change our internal control over financial reporting inresponse to this matter in this third or any future quarter, other than toproscribe our engaging in related party hedging transactions in the future.

 

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**PART II****  OTHERINFORMATION**

 

**Item 1.****  LegalProceedings**

 

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

 

**Item 4. Submission of Matters to a Vote of SecurityHolders**

 

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

 

1.               Toelect three Class III directors to hold office for a three-year term expiringat the Annual Meeting of Stockholders occurring in the year 2006 or until theelection and qualification of their respective successors.

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

 

2.               Toratify the selection of PricewaterhouseCoopers LLP as our independentaccountants for the fiscal year ending December 31, 2003.

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

 

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

 

(a)                                  Exhibits

 

11*                             Statementregarding computation of earnings per share.

 

31.1*                    ChiefExecutive Officer Certification Pursuant to Section 13a-14 of the SecuritiesExchange Act.

 

31.2*                    ChiefFinancial Officer Certification Pursuant to Section 13a-14 of the SecuritiesExchange Act.

 

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

 

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

 

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* Filedherewith.

 

(b)                                 Reports on Form 8-K

 

A report on Form 8-K was filedwith the SEC on April 14, 2003, announcing that MarkWest Energy Partners completedits acquisition of Pinnacle Natural Gas Company and certain affiliates on March28, 2003, amended by Form 8-K/A filed with the SEC on June 11, 2003, whichincluded the unaudited financial statements of PNG Corporation andsubsidiaries.

 

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

 

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

 

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**SIGNATURE**

 

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

 

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

 

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