**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  September 30, 2003**                                                                                                                                                                                                                                                                                                              |
|       |   |                                                                                                                                                                                                                                                                                                                                                                |
|       |   | **OR**                                                                                                                                                                                                                                                                                                                                                              |
|       |   |                                                                                                                                                                                                                                                                                                                                                                |
| **o**      |   | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                                                                                                                                       |
|       |   |                                                                                                                                                                                                                                                                                                                                                                |
|       |   | **For the transition period  from                             to                        ** |

 

**Commission File Number 1-11566**

 

**MARKWESTHYDROCARBON, INC.**

(Exact name of registrantas specified in its charter)

** **

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

 

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

(Address of principal executive offices)

 

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

 

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

Yes  ý  No  o

 

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

Yes  o  No  ý

 

The registrant had 9,384,013shares of common stock, $.01 per share par value, outstanding as of

September 30, 2003.

 

 

----

 
| **PART I—FINANCIAL  INFORMATION** |                                                                                                                                     |
|----------------------------------------|------------------------------------------------------------------------------------------------------------------------------------------|
| Item 1.                                | Consolidated  Financial Statements                                                                                                       |   |
|                                   | Condensed  Consolidated Balance Sheets (Unaudited) at September 30, 2003 and December  31, 2002                                          |   |
|                                   | Condensed  Consolidated Statements of Operations (Unaudited) for the Three and Nine  Months Ended September 30, 2003 and 2002       |   |
|                                   | Condensed  Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended  September 30, 2003 and 2002                      |   |
|                                   | Condensed  Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the  Nine Months Ended September 30, 2003 |   |
|                                   | Notes  to the Unaudited Condensed Consolidated Financial Statements                                                                      |   |
| Item  2.                               | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                                              |   |
| Item  3.                               | Quantitative  and Qualitative Disclosures about Market Risk                                                                              |   |
| Item 4.                                | Controls and  Procedures                                                                                                                 |   |
|                                   |                                                                                                                                     |   |
| **PART II—OTHER INFORMATION**     |                                                                                                                                     |
|                                   |                                                                                                                                     |   |
| Item 1.                                | Legal Proceedings                                                                                                                        |   |
| Item 6.                                | Exhibits 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  Offered 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 NGLsis the energy equivalent of six Mcf of natural gas.

 

----

 

## **PART I—FINANCIALINFORMATION**

## **Item 1.  Consolidated Financial Statements**

 

**MARKWEST HYDROCARBON, INC.**

**CONDENSED CONSOLIDATED BALANCE SHEETS**

**(UNAUDITED)**

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

** **
|                                                                                                                               |   | **September 30, 2003** |    | **December 31, 2002** |   |
|------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------|---------|-----------------------|--------|
| **ASSETS**                                                                                                                         |   |                   |    |                  |   |
| Current  assets:                                                                                                                   |   |                   |    |                  |   |
| Cash  and cash equivalents                                                                                                         |   | $                      | 7,580   |                  | $      | 6,410 |   |
| Receivables,  net                                                                                                                  |   | 13,695                 |    | 25,444                |   |
| Inventories                                                                                                                        |   | 6,553                  |    | 4,347                 |   |
| Prepaid  replacement natural gas                                                                                                   |   | 3,566                  |    | 1,197                 |   |
| Other  assets                                                                                                                      |   | 2,314                  |    | 1,240                 |   |
| Assets  held for sale                                                                                                              |   | 5,046                  |    | —                |   |
| Total  current assets                                                                                                              |   | 38,754                 |    | 38,638                |   |
|                                                                                                                               |   |                   |    |                  |   |
| Property,  plant and equipment:                                                                                                    |   |                   |    |                  |   |
| Gas  processing, gathering, storage and marketing equipment                                                                        |   | 163,705                |    | 121,851               |   |
| Oil  and gas properties and equipment, full cost method                                                                            |   | —                 |    | 139,234               |   |
| Land,  buildings and other equipment                                                                                               |   | 5,939                  |    | 7,540                 |   |
| Construction  in progress                                                                                                          |   | 893                    |    | 1,610                 |   |
|                                                                                                                               |   | 170,537                |    | 270,235               |   |
| Less:  accumulated depreciation, depletion and amortization                                                                        |   | (39,496                | )       | (58,717               | )      |
| Total  property and equipment, net                                                                                                 |   | 131,041                |    | 211,518               |   |
|                                                                                                                               |   |                   |    |                  |   |
| Risk  management asset                                                                                                             |   | 99                     |    | 749                   |   |
| Intangible  assets, net of accumulated amortization of $2,649 and $2,018, respectively                                             |   | 1,502                  |    | 2,138                 |   |
| Note  receivables from employees                                                                                                   |   | 217                    |    | 271                   |   |
| Assets  held for sale                                                                                                              |   | 116,131                |    | —                |   |
|                                                                                                                               |   |                   |    |                  |   |
| Total  assets                                                                                                                      |   | $                      | 287,744 |                  | $      | 253,314 |   |
|                                                                                                                               |   |                   |    |                  |   |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                                     |   |                   |    |                  |   |
| Current  liabilities:                                                                                                              |   |                   |    |                  |   |
| Accounts  payable                                                                                                                  |   | $                      | 19,746  |                  | $      | 26,063 |   |
| Accrued  liabilities                                                                                                               |   | 15,438                 |    | 8,145                 |   |
| Risk  management liability                                                                                                         |   | 4,396                  |    | 13,719                |   |
| Liabilities  held for sale                                                                                                         |   | 14,334                 |    | —                |   |
| Total  current liabilities                                                                                                         |   | 53,914                 |    | 47,927                |   |
|                                                                                                                               |   |                   |    |                  |   |
| Deferred  income taxes                                                                                                             |   | 4,015                  |    | 35,685                |   |
| Long-term  debt                                                                                                                    |   | 63,300                 |    | 64,223                |   |
| Risk  management liability                                                                                                         |   | 375                    |    | 2,115                 |   |
| Other  long-term liabilities                                                                                                       |   | 46                     |    | 4,011                 |   |
| Minority  interest in consolidated subsidiary                                                                                      |   | 53,987                 |    | 46,001                |   |
| Liabilities  held for sale                                                                                                         |   | 49,678                 |    | —                |   |
| Commitments  and contingencies (Note 11)                                                                                           |   |                   |    |                  |   |
|                                                                                                                               |   |                   |    |                  |   |
| 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, 9,466,805 and 9,417,511  shares issued and outstanding, respectively |   | 95                     |    | 95                    |   |
| Additional  paid-in capital                                                                                                        |   | 49,214                 |    | 42,750                |   |
| Retained  earnings                                                                                                                 |   | 15,582                 |    | 19,693                |   |
| Accumulated  other comprehensive loss, net of tax                                                                                  |   | (1,920                 | )       | (8,858                | )      |
| Treasury  stock, 82,792 and 55,507 shares, respectively                                                                            |   | (542                   | )       | (328                  | )      |
| Total  stockholders’ equity                                                                                                   |   | 62,429                 |    | 53,352                |   |
|                                                                                                                               |   |                   |    |                  |   |
| Total  liabilities and stockholders’ equity                                                                                   |   | $                      | 287,744 |                  | $      | 253,314 |   |

 

The accompanying notesare an integral part of these unaudited financial statements.

 

1

----

**MARKWEST HYDROCARBON, INC.**

**CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS**

**(UNAUDITED)**

 
|                                                                                    |   | **Three Months Ended****September  30,**          |   | **Nine Months Ended****September  30,** |   |
|-----------------------------------------------------------------------------------------|--------|---------------------------------------------------|--------|-----------------------------------------|--------|
|                                                                                    |   | **2003**                                          |   | **2002**                                |   | **2003** |   | **2002** |   |
|                                                                                    |   | **(****in thousands, except per share data****)** |   |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Revenue                                                                                 |   | $                                                 | 48,228 |                                    | $      | 29,540 |   | $ | 146,767 |   | $ | 105,430 |   |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Operating  expenses:                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Purchased  product costs                                                                |   | 44,521                                            |   | 26,313                                  |   | 134,881 |   | 86,658 |   |
| Facility  expenses                                                                      |   | 5,327                                             |   | 3,770                                   |   | 14,381 |   | 11,941 |   |
| Selling,  general and administrative expenses                                           |   | 3,426                                             |   | 2,313                                   |   | 9,064 |   | 6,526 |   |
| Depreciation  and amortization                                                          |   | 2,220                                             |   | 1,341                                   |   | 5,791 |   | 4,243 |   |
| Loss  on sale of terminals                                                              |   | 55                                                |   | —                                  |   | 55 |   | — |   |
| Total  operating expenses                                                               |   | 55,549                                            |   | 33,737                                  |   | 164,172 |   | 109,368 |   |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Loss  from operations                                                                   |   | (7,321                                            | )      | (4,197                                  | )      | (17,405 | ) | (3,938 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Other  income and (expenses):                                                           |   |                                              |   |                                    |   |   |   |   |   |
| Interest  income                                                                        |   | 24                                                |   | 19                                      |   | 68 |   | 41 |   |
| Interest  expense                                                                       |   | (1,139                                            | )      | (753                                    | )      | (4,244 | ) | (2,995 | ) |
| Write-down  of deferred financing costs                                                 |   | —                                            |   | —                                  |   | — |   | (2,977 | ) |
| Gain  on sale to related party                                                          |   | —                                            |   | 77                                      |   | 188 |   | 141 |   |
| Minority  interest in net income of consolidated subsidiary                             |   | (1,607                                            | )      | (1,122                                  | )      | (3,342 | ) | (1,480 | ) |
| Other  income (expense)                                                                 |   | 31                                                |   | (36                                     | )      | 15 |   | (62 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Loss  from continuing operations before income taxes                                    |   | (10,012                                           | )      | (6,012                                  | )      | (24,720 | ) | (11,270 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Benefit  for income taxes                                                               |   | (3,701                                            | )      | (2,345                                  | )      | (9,058 | ) | (4,395 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Loss  from continuing operations                                                        |   | (6,311                                            | )      | (3,667                                  | )      | (15,662 | ) | (6,875 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Discontinued  operations (Note 3):                                                      |   |                                              |   |                                    |   |   |   |   |   |
| Income  (loss) from discontinued exploration and production operations, net of tax      |   | (1,260                                            | )      | 505                                     |   | 2,788 |   | 1,815 |   |
| Gain  on sale of properties, net of tax                                                 |   | 593                                               |   | —                                  |   | 14,862 |   | — |   |
| Income  (loss) from discontinued operations                                             |   | (667                                              | )      | 505                                     |   | 17,650 |   | 1,815 |   |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Income  (loss) before cumulative effect of accounting change                            |   | (6,978                                            | )      | (3,162                                  | )      | 1,988 |   | (5,060 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Cumulative  effect of change in accounting for asset retirement obligations, net of tax |   | —                                            |   | —                                  |   | (29 | ) | — |   |
| Net  income (loss)                                                                      |   | $                                                 | (6,978 | )                                       | $      | (3,162 | ) | $ | 1,959 |   | $ | (5,060 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Basic  earnings (loss) per share of common stock                                        |   | $                                                 | (0.74  | )                                       | $      | (0.34 | ) | $ | 0.21 |   | $ | (0.54 | ) |
| Earnings  (loss) per share assuming dilution                                            |   | $                                                 | (0.74  | )                                       | $      | (0.34 | ) | $ | 0.21 |   | $ | (0.54 | ) |
|                                                                                    |   |                                              |   |                                    |   |   |   |   |   |
| Weighted  average number of outstanding shares of common stock:                         |   |                                              |   |                                    |   |   |   |   |   |
| Basic                                                                                   |   | 9,378                                             |   | 9,374                                   |   | 9,364 |   | 9,369 |   |
| Assuming  dilution                                                                      |   | 9,400                                             |   | 9,385                                   |   | 9,380 |   | 9,385 |   |

 

The accompanying notesare an integral part of these financial unaudited statements.

 

2

----

 

**MARKWEST HYDROCARBON, INC.**

**CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(UNAUDITED)**

 
|                                                                                                       |   | **Nine Months  Ended September 30,** |   |
|------------------------------------------------------------------------------------------------------------|--------|--------------------------------------|--------|
|                                                                                                       |   | **2003**                             |   | **2002** |   |
|                                                                                                       |   | **(in thousands)**                   |   |
| **Cash flows from operating activities:**                                                                  |   |                                 |   |   |   |
| Net  income (loss)                                                                                         |   | $                                    | 1,959  |   | $ | (5,060 | ) |
| 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                                                                  |   | 18,814                               |   | 15,788 |   |
| Amortization  of deferred financing costs included in interest expense                                     |   | 1,270                                |   | 975 |   |
| Write-off  of deferred financing costs                                                                     |   | —                               |   | 2,977 |   |
| Minority  interest in net income of consolidated subsidiary                                                |   | 3,342                                |   | 1,480 |   |
| Derivative  ineffectiveness and non-cash mark-to-market adjustments                                        |   | (2,207                               | )      | 1,710 |   |
| Reclassification  of Enron hedges to purchased product costs                                               |   | (153                                 | )      | (648 | ) |
| Deferred  income taxes                                                                                     |   | (4,846                               | )      | (4,062 | ) |
| Gain  on sale of San Juan Basin properties                                                                 |   | (23,035                              | )      | — |   |
| Cost  of exiting hedges                                                                                    |   | (3,440                               | )      | — |   |
| Other                                                                                                      |   | 427                                  |   | (95 | ) |
| Changes  in operating assets and liabilities:                                                              |   |                                 |   |   |   |
| (Increase)  decrease in receivables                                                                        |   | 15,046                               |   | 3,075 |   |
| (Increase)  decrease in inventories                                                                        |   | (2,540                               | )      | (320 | ) |
| (Increase)  decrease in prepaid expenses and other assets                                                  |   | (3,941                               | )      | 8,322 |   |
| Increase  (decrease) in accounts payable and accrued liabilities                                           |   | 863                                  |   | 6,628 |   |
| Increase  (decrease) in other long-term liabilities                                                        |   | 1,565                                |   | 3,089 |   |
|                                                                                                       |   |                                 |   |   |   |
| Net  cash flow provided by operating activities                                                            |   | 3,153                                |   | 33,859 |   |
|                                                                                                       |   |                                 |   |   |   |
| **Cash flows from investing activities:**                                                                  |   |                                 |   |   |   |
| Pinnacle  acquisition, net of cash acquired                                                                |   | (38,238                              | )      | — |   |
| Lubbock  pipeline acquisition                                                                              |   | (12,222                              | )      | — |   |
| Proceeds  from sale of San Juan Basin properties, net of costs to dispose                                  |   | 55,007                               |   | — |   |
| Capital  expenditures                                                                                      |   | (24,968                              | )      | (25,433 | ) |
| Proceeds  from sales of terminals                                                                          |   | 2,438                                |   | 87 |   |
| Proceeds  from sale of assets to related parties                                                           |   | 212                                  |   | 263 |   |
|                                                                                                       |   |                                 |   |   |   |
| Net  cash used in investing activities                                                                     |   | (17,771                              | )      | (25,083 | ) |
|                                                                                                       |   |                                 |   |   |   |
| **Cash flows from financing activities:**                                                                  |   |                                 |   |   |   |
| Proceeds  from long-term debt                                                                              |   | 86,835                               |   | 48,910 |   |
| Repayment  of long-term debt                                                                               |   | (75,130                              | )      | (98,945 | ) |
| Proceeds  from initial public offering, net of transaction costs                                           |   | —                               |   | 43,012 |   |
| Proceeds  from private placement of MarkWest Energy Partners’ common units, net of  transaction costs |   | 9,764                                |   | — |   |
| Capital  contribution from MarkWest Energy GP, L.L.C. interest holders                                     |   | 17                                   |   | — |   |
| Debt  issuance costs                                                                                       |   | (811                                 | )      | (1,804 | ) |
| Distributions  to MarkWest Energy Partners’ unitholders                                               |   | (5,173                               | )      | (514 | ) |
| Exercise  of stock options                                                                                 |   | 333                                  |   | — |   |
| Net  issuance (buyback) of treasury shares                                                                 |   | (158                                 | )      | 141 |   |
| Payment  on share purchase notes                                                                           |   | —                               |   | 13 |   |
|                                                                                                       |   |                                 |   |   |   |
| Net  cash provided by (used in) financing activities                                                       |   | 15,677                               |   | (9,187 | ) |
|                                                                                                       |   |                                 |   |   |   |
| Effect  of exchange rate on changes in cash                                                                |   | 111                                  |   | 17 |   |
| Net  increase (decrease) in cash and cash equivalents                                                      |   | 1,170                                |   | (394 | ) |
| Cash  and cash equivalents at beginning of period                                                          |   | 6,410                                |   | 2,340 |   |
| Cash  and cash equivalents at end of period                                                                |   | $                                    | 7,580  |   | $ | 1,946 |   |

 

The accompanying notesare an integral part of these unaudited financial statements.

 

3

----

 

**MARKWEST HYDROCARBON, INC.**

**CONDENSEDCONSOLIDATED STATEMENT 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                             | )      | 9                 |   | 6,117                            |   | (6,070                 | )      | (56                   | )      | —                                                    |   | —                                |   |
|                                                      |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                      |   |                                  |   |
| Comprehensive  income:                                    |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                      |   |                                  |   |
| Net  income                                               |   | —                       |   | —                         |   | —            |   | —                           |   | 1,959                  |   | —                |   | —                                                    |   | 1,959                                 |   |
| Other  comprehensive income:                              |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                      |   |                                  |   |
| Foreign  currency translation, net of tax                 |   | —                       |   | —                         |   | —            |   | —                           |   | —                 |   | —                |   | 3,796                                                     |   | 3,796                                 |   |
| Risk  management activities, net of tax                   |   | —                       |   | —                         |   | —            |   | —                           |   | —                 |   | —                |   | 3,142                                                     |   | 3,142                                 |   |
| Comprehensive  income, net of tax                         |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                      |   | 8,897                                 |   |
|                                                      |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                      |   |                                  |   |
| Acquisition  of treasury stock, net                       |   | —                       |   | (28                            | )      | —            |   | 5                                |   | —                 |   | (158                  | )      | —                                                    |   | (153                                  | )      |
| Exercise  of options                                      |   | 47                           |   | —                         |   | —            |   | 333                              |   | —                 |   | —                |   | —                                                    |   | 333                                   |   |
|                                                      |   |                         |   |                           |   |              |   |                             |   |                   |   |                  |   |                                                      |   |                                  |   |
| Balance,  September 30, 2003                              |   | 9,467                        |   | (83                            | )      | $                 | 95     |                             | $      | 49,214                 |   | $                     | 15,582 |                                                      | $      | (542                                  | )      | $ | (1,920 | ) | $ | 62,429 |   |

 

The accompanying notesare an integral part of these unaudited financial statements.

 

4

----

 

**MARKWEST HYDROCARBON, INC.**

**NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS**

 

**1.             General**

 

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

 

We haveprepared the unaudited financial statements presented herein in accordance withthe instructions to Form 10-Q. The year-end balance sheet data was derived fromaudited financial statements but does not include all disclosures required byaccounting principles generally accepted in the United States. Please read theinterim unaudited consolidated financial statements in conjunction with theConsolidated Financial Statements and attached notes for the year endedDecember 31, 2002, included in our Annual Report on Form 10-K, as filed withthe Securities and Exchange Commission. In the opinion of management, we havemade all necessary normal recurring adjustments for a fair presentation of theresults for the unaudited interim periods.

 

We base the effective corporate tax rate for interimperiods on the estimated annual effective corporate tax rate. The effective taxrate for continuing operations varies from statutory rates primarily due tostate income taxes.

 

**2.     Sale of San Juan Basin Properties**

 

During thethird quarter of 2003, MarkWest Hydrocarbon completed the sales of theremainder of its San Juan Basin oil and gas properties to certain third partiesfor approximately $6.1 million, net of transaction costs and closing adjustments.Previously, MarkWest Hydrocarbon closed on the sale of the majority of its SanJuan Basin properties in the second quarter of 2003. We recognized net pretaxgains of $3.3 million and $23.0 million on the sales for the three and ninemonths ended September 30, 2003, which are included in Discontinued Operations:Gain on Sale of Properties.  Theproceeds from the sales were used for working capital and general corporatepurposes.

 

**3.     Discontinued Operations and Assets andLiabilities Held For Sale**

 

During the third quarterof 2003, our Board of Directors approved a plan to sell our Canadian oil andgas properties. On November 12, 2003, we announced we had entered into anagreement to sell one of our Canadian subsidiaries, which owns most of our Canadianproperties, to a third party (see Note 15). Management also intends to disposeof our remaining U.S. and Canadian oil and gas properties within the next yearas we discontinue our exploration and production business.

 

Revenues from thediscontinued operations were $7.6 million and $7.7 million for the three monthsended September 30, 2003 and 2002, respectively, and $27.5 million and $22.2million for the nine months ended September 30, 2003 and 2002, respectively.Pretax income (loss) from discontinued operations was ($1.6) million and $0.3million for the three months ended September 30, 2003 and 2002, respectively,and $3.5 million and $2.1 million for the nine months ended September 30, 2003and 2002, respectively.

 

The earnings(loss) per share impact from discontinued operations was $(0.07) and $0.05 perbasic and diluted share for the three months ended September 30, 2003 and 2002,respectively, and $1.88 and $0.19 per basic and diluted share for the ninemonths ended September 30, 2003 and 2002, respectively. The earnings per shareimpact from the cumulative effect of the change in accounting for assetretirement obligations was not significant for 2003.

 

**4.     PinnacleAcquisition**

 

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

 

5

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The PinnacleAcquisition 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.

 

Thepurchase price was allocated as follows (in thousands):

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

 

*Pro Forma Results of Operations*

 

The following tablereflects the unaudited pro forma consolidated results of operations for thethree months ended September 30, 2002, and the nine months ended September 30,2003 and 2002, as though the Pinnacle Acquisition had occurred on January 1,2002. These unaudited pro forma results have been prepared for comparative purposesonly and are not necessarily indicative of future results.

 
|                                |   | **Three  Months  Ended**                       |   | **Nine  Months Ended September 30,** |   |
|-------------------------------------|--------|------------------------------------------------|--------|--------------------------------------|--------|
|                                |   | **September  30, 2002**                        |   | **2003**                             |   | **2002** |   |
|                                |   | **(in thousands, except per share  data****)** |   |
| Revenue                             |   | $                                              | 40,422 |                                 | $      | 164,554 |   | $ | 135,520 |   |
| Loss from continuing operations     |   | $                                              | (3,962 | )                                    | $      | (14,436 | ) | $ | (7,680 | ) |
| Net income (loss)                   |   | $                                              | (3,457 | )                                    | $      | 2,703 |   | $ | (5,865 | ) |
| Basic net income (loss) per share   |   | $                                              | (0.37  | )                                    | $      | 0.29 |   | $ | (0.63 | ) |
| Diluted net income (loss) per share |   | $                                              | (0.37  | )                                    | $      | 0.29 |   | $ | (0.63 | ) |

 

**5.****              LubbockPipeline Acquisition**

 

On September 2, 2003, ourconsolidated subsidiary, MarkWest Energy Partners, through its wholly ownedsubsidiary MarkWest Pinnacle L.P., completed the acquisition (the “LubbockPipeline Acquisition”) of a 68-mile intrastate gas transmission pipeline nearLubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2million. The transaction was financed through borrowings under MarkWest EnergyPartners’ existing credit facility. The acquisition was accounted for as a purchasebusiness combination. The pro forma results of operations of the LubbockPipeline Acquisition have not been presented, as they are not significant.

 

**6.****           Terminal Dispositions**

 

Our Board of Directorshas approved a plan to sell any of our three NGL product terminals, which areconsidered to be non-strategic assets. On July 15, 2003, we sold our Lordstown,Ohio terminal to a third party for approximately $0.7 million, including $0.2million for on-hand inventory. On September 2, 2003, we sold our Lynchburg,Virginia terminal to a third party for approximately $1.6 million plus on-handinventory. As a result of the two sales, we incurred a loss of less than $0.1million.

 

6

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**7.     Stock Dividend**

 

On July 10, 2003, our board ofdirectors declared a stock dividend of one share of MarkWest Hydrocarbon’scommon stock for each ten shares of common stock held by our stockholders. Thestock dividend was paid on August 11, 2003, to the stockholders of record as ofthe close of business on July 31, 2003. All periods presented have beenadjusted to give effect to the stock dividend.

 

**8.****           Private Placement**

 

Ourconsolidated subsidiary, MarkWest Energy Partners, sold 375,000 common units intwo installments at a price of $26.23 per unit in a private placementtransaction to certain accredited investors. The first installment of 300,031units was completed on June 27, 2003, and grossed approximately $7.9 million.The second installment of 74,969 units was completed on July 10, 2003, andgrossed approximately $1.9 million. Transaction costs for both installmentswere less than $0.1 million. MarkWest Energy Partners’ general partner paid itspro rata contribution in July 2003 after the second installment was completed.MarkWest Energy Partners primarily used the net proceeds from both installmentsto pay down debt under its credit facility.

 

**9.****           Related Party Transactions**

 

*MarkWest Hydrocarbon, Inc.*

 

Through our whollyowned subsidiary, MarkWest Resources, Inc., we held varied undivided interestsin several exploration and production assets in which MAK-J Energy PartnersLtd. (“MAK-J”) also owns an undivided interest, varying from 25% to 51%. Thegeneral partner of MAK-J is a corporation owned and controlled by our currentChief Executive Officer, John M. Fox. One other current officer is a limitedpartner in MAK-J. As of September 30, 2003, we have receivables due from MAK-J,representing its share of operating and capital costs generated in the normalcourse of business, of approximately $0.7 million.

 

*MarkWest Energy Partners*

 

During the third quarterof 2003, MarkWest Hydrocarbon purchased a 0.3% interest in MarkWest Energy GP, L.L.C., the general partnerof MarkWest Energy Partners, and 867 subordinated units of MarkWestEnergy Partners from a former officer. We had originally sold the generalpartner interest and subordinated units to this individual in May 2002. Inreturn for the general partner interest and the subordinated units, weexchanged the former officer’s $10,000 note receivable and related accruedinterest and paid approximately $27,000 in cash, for total consideration ofapproximately $37,000.  The purchaseprice for MarkWest Energy Partners subordinated units was based on market valueof MarkWest Energy Partners common units, discounted for the subordination. Thepurchase price for the general partner interest was based on a formula includedin the parties’ original purchase and sale agreement.

 

**10.  Segment Reporting**

 

Our operations areclassified into two reportable segments:

 

(1)          Gatheringand Processing—gathering and processing of natural gas and the transportation,fractionation and storage of natural gas liquid (our gathering and processingoperations are conducted by MarkWest Energy Partners); and

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

 

A previous thirdsegment, Exploration and Production, was discontinued in the third quarter of2003. As a

result,this segment is no longer included in this disclosure.

 

On May 24, 2002, we spunoff our gathering and processing assets into MarkWest Energy Partners. Theformation and initial public offering (the “IPO”) of MarkWest Energy Partners(the IPO closed on May 24, 2002) and the subsequent change to the structure of ourinternal organization caused the composition of our reportable

 

7

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segmentsto change in the fourth quarter of 2002. Prior to the fourth quarter of 2002,we classified our operations into two reportable segments:

 

(1)          Explorationand Production—explore for and produce natural gas; (which has since beendiscontinued); and

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

 

Although the three and nine months ended September 30,2003 reflects our revised segments, information prior to May 24, 2002, was notrevised to reflect the change in segmentation because no transfer pricingexisted between Gathering and Processing and Marketing up until that point intime. In connection with the formation of MarkWest Energy Partners, certaincontracts were executed which established the basis of fees for servicesrendered by processing MarkWest Hydrocarbon’s natural gas. No such arrangementexisted prior to the formation of MarkWest Energy Partners. As a result, it wasnot practicable to revise certain prior period segment information to conformto our current presentation. In light of the discontinuance of our Explorationand Production segment during the third quarter of 2003, revenue and pretaxincome for this segment for all periods presented is included in Note 3. Priorperiod information for the Gathering, Processing and Marketing segment is shownon the face of the Statement of Operations, as this is the only segmentincluded in continuing operations for 2002.

 

We evaluate theperformance of our segments and allocate resources to them based on operatingincome.  There were no intersegmentrevenues prior to May 24, 2002.

 

The tables below presents information about operatingincome for the reported segments for the three and nine months ended September30, 2003. Operating income for each segment includes total revenues lesspurchased products costs, operating expenses, depreciation and depletion andexcludes selling, general and administrative expenses, interest expense,interest income, one-time charges and income taxes.

 
|                                       |   | **MarkWest  Hydrocarbon** |   |
|--------------------------------------------|--------|---------------------------|--------|
|                                       |   |                      |   | **MarkWest   Energy  Partners** |   |   |   |   |   |
|                                       |   | **Marketing**             |   | **Gathering  &  Processing** |   | **Eliminating  Entries** |   | **Total** |   |
|                                       |   | **(in thousands)**        |   |
| **Three  Months Ended September 30, 2003** |   |                      |   |   |   |   |   |   |   |
| Revenues  from external customers          |   | $                         | 29,340 |   | $ | 18,888 |   | $ | — |   | $ | 48,228 |   |
| Intersegment  revenues                     |   | $                         | — |   | $ | 12,524 |   | $ | (12,524 | ) | $ | — |   |
| Segment  operating income (loss)           |   | $                         | (9,320 | ) | $ | 5,480 |   | $ | — |   | $ | (3,840 | ) |

 
|                                       |   | **MarkWest  Hydrocarbon** |    |
|--------------------------------------------|--------|---------------------------|---------|
|                                       |   |                      |    | **MarkWest  Energy  Partners** |   |   |   |   |   |
|                                       |   | **Marketing**             |    | **Gathering  &  Processing** |   | **Eliminating**

**Entries** |   | **Total** |   |
|                                       |   | **(in thousands)**        |    |
| **Three  Months Ended September 30, 2003** |   |                      |    |   |   |   |   |   |   |
| Revenues  from external customers          |   | $                         | 104,206 |   | $ | 42,741 |   | $ | — |   | $ | 146,767 |   |
| Intersegment  revenues                     |   | $                         | —  |   | $ | 36,000 |   | $ | (36,000 | ) | $ | — |   |
| Segment  operating income (loss)           |   | $                         | (21,571 | ) | $ | 13,285 |   | $ | — |   | $ | (8,286 | ) |
|                                       |   |                      |    |   |   |   |   |   |   |

 

8

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|                                                        |   | **Three Months Ended  September 30, 2003** |    | **Nine Months Ended  September 30, 2003** |   |
|-------------------------------------------------------------|--------|--------------------------------------------|---------|-------------------------------------------|--------|
|                                                        |   | **(in thousands)**                         |    |
| Total segment operating  loss                               |   | $                                          | (3,840  | )                                         | $      | (8,286 | ) |
| Loss  on sale of terminals                                  |   | (55                                        | )       | (55                                       | )      |
| Selling, general and administrative expenses                |   | (3,426                                     | )       | (9,064                                    | )      |
| Interest  income                                            |   | 24                                         |    | 68                                        |   |
| Interest  expense                                           |   | (1,139                                     | )       | (4,244                                    | )      |
| Write-off  of deferred financing costs                      |   | —                                     |    | —                                    |   |
| Gain  on sale to related party                              |   | —                                     |    | 188                                       |   |
| Minority interest in net income of consolidated  subsidiary |   | (1,607                                     | )       | (3,342                                    | )      |
| Other  income                                               |   | 31                                         |    | 15                                        |   |
| Loss  from continuing operations before income taxes        |   | $                                          | (10,012 | )                                         | $      | (24,720 | ) |

** **

**11.  Commitmentsand Contingencies**

 

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

 

**12.  Stockand Unit Compensation**

 

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

 

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

 
|                                                                                                                                         |   | **Three  Months Ended  September 30,**     |   | **Nine  Months Ended  September 30,** |   |
|----------------------------------------------------------------------------------------------------------------------------------------------|--------|--------------------------------------------|--------|---------------------------------------|--------|
|                                                                                                                                         |   | **2003**                                   |   | **2002**                              |   | **2003** |   | **2002** |   |
|                                                                                                                                         |   | **(in  thousands, except per share data)** |   |
| Net  income (loss), as reported                                                                                                              |   | $                                          | (6,978 | )                                     | $      | (3,162 | ) | $ | 1,959 |   | $ | (5,060 | ) |
| Add:  Compensation expense included in reported net income                                                                                   |   | 72                                         |   | —                                |   | 343 |   | — |   |
| Deduct:  total stock-based employee compensation expense determined under fair value  based method for all awards, net of related tax effect |   | (180                                       | )      | (105                                  | )      | (636 | ) | (314 | ) |
| Pro  forma net income (loss)                                                                                                                 |   | $                                          | (7,086 | )                                     | $      | (3,267 | ) | $ | 1,666 |   | $ | (5,374 | ) |
|                                                                                                                                         |   |                                       |   |                                  |   |   |   |   |   |
| Earnings  (loss) per share:                                                                                                                  |   |                                       |   |                                  |   |   |   |   |   |
| Basic,  as reported                                                                                                                          |   | $                                          | (0.74  | )                                     | $      | (0.34 | ) | $ | 0.21 |   | $ | (0.54 | ) |
| Basic,  pro forma                                                                                                                            |   | $                                          | (0.76  | )                                     | $      | (0.35 | ) | $ | 0.18 |   | $ | (0.57 | ) |
| Diluted,  as reported                                                                                                                        |   | $                                          | (0.74  | )                                     | $      | (0.34 | ) | $ | 0.21 |   | $ | (0.54 | ) |
| Diluted,  pro forma                                                                                                                          |   | $                                          | (0.75  | )                                     | $      | (0.35 | ) | $ | 0.18 |   | $ | (0.57 | ) |

 

Compensation expense for the variable plan, includingrestricted unit grants, is measured using the market price of MarkWest EnergyPartners’ common units on the last trading day of the corresponding quarter andis amortized into earnings over the period of service. Our stock options areissued under a fixed plan. Accordingly, compensation expense is not recognizedfor stock options unless the options were granted at an exercise price lowerthan market on the grant date.

 

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**13.  Asset RetirementObligations**

 

On January 1, 2003, weadopted SFAS No. 143, *Asset RetirementObligations*.  SFAS No. 143requires entities to record the fair value of a liability for an assetretirement obligation in the period in which it is incurred and a correspondingincrease in the carrying amount of the related long-lived asset. Subsequently,the asset retirement cost will be allocated to expense using a systematic andrational method. During the first quarter of 2003, we recorded a net-of-taxcumulative effect of change in accounting principle charge of $29,000 ($63,000before tax), an asset retirement obligation of $3.4 million. We also increasednet properties $2.4 million in accordance with the provisions of SFAS No. 143.There was no impact on our cash flows as a result of adopting SFAS No. 143. Thepro forma asset retirement obligation would have been $2.5 million at January1, 2002 had we adopted SFAS No. 143 on January 1, 2002. The asset retirementobligation, which is included on the Unaudited Condensed Consolidated BalanceSheet in Other Long-Term Liabilities, was $3.8 million at September 30, 2003.

 

Forthe periods ended September 30, 2002, the pro forma effect on net income andearnings per share, had we adopted SFAS No. 143 on January 1, 2002, would havebeen as follows:

 
|             |   | **Three  Months Ended  September 30, 2002** |   | **Nine Months  Ended  September 30, 2002** |   |
|------------------|--------|---------------------------------------------|--------|--------------------------------------------|--------|
|             |   | **As  Reported**                            |   | **Pro   Forma**                            |   | **As   Reported** |   | **Pro   Forma** |   |
|             |   | **(in  thousands, except per share data)**  |   |
| Net loss         |   | $                                           | (3,162 | )                                          | $      | (3,512 | ) | $ | (5,060 | ) | $ | (6,110 | ) |
| Loss  per share: |   |                                        |   |                                       |   |   |   |   |   |
| Basic            |   | $                                           | (0.34  | )                                          | $      | (0.37 | ) | $ | (0.54 | ) | $ | (0.65 | ) |
| Diluted          |   | $                                           | (0.34  | )                                          | $      | (0.37 | ) | $ | (0.54 | ) | $ | (0.65 | ) |

 

The following is areconciliation of the asset retirement obligation for the three months endedSeptember 30, 2003 (in thousands):

 
| Asset retirement obligation as of July 1,  2003       |   | $   | 3,277  |   |
|-------------------------------------------------------|--------|-----|--------|--------|
| Liability accrued upon capital  expenditures          |   | 479 |   |
| Liability settled                                     |   | (20 | )      |
| Accretion of discount expense                         |   | 43  |   |
| Asset retirement  obligation as of September 30, 2003 |   | $   | 3,779  |   |

 

**14.  Recent Accounting Pronouncements**

 

In May 2003, theFASB issued Statement of Financial Accounting Standards No. 150 (“SFASNo. 150”), “Accounting for Certain Financial Instruments withCharacteristics of Both Liabilities and Equity.” This statement establishesstandards for the measurement and classification of certain financial instrumentswith characteristics of both liabilities and equity. SFAS No. 150 iseffective for financial instruments entered into or modified after May 31,2003, and otherwise effective the first interim period beginning afterJune 15, 2003. The adoption of this standard did not have any impact onour financial position or results of operations.

 

In April 2003, theFASB issued Statement of Financial Accounting Standards No. 149 (“SFASNo. 149”), “Amendment of Statement 133 on Derivative Instruments andHedging Activities.” This statement amends and clarifies financial accountingand reporting for derivative instruments, including certain derivativeinstruments embedded in other contracts and for hedging activities underStatement of Financial Accounting Standards No. 133 (“SFAS No. 133”),“Accounting for Derivative Instruments and Hedging Activities.” SFASNo. 149 is effective for contracts entered into or modified afterJune 30, 2003 and should be applied prospectively. However, provisionsrelated to SFAS No. 133 Implementation Issues effective for fiscalquarters beginning prior to June 15, 2003 should continue to be applied inaccordance with their respective dates. The adoption of this standard did nothave any impact on our financialposition or results of operations***.***

 

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**15.  Subsequent Events**

 

***MarkWest Hydrocarbon, Inc. Credit FacilityAmendment***

 

On October 6,2003, we amended our credit facility (the “Credit Facility”) with variousfinancial institutions.  Prior toamendment the $60 million revolving credit facility was comprised of twocomponents: (a) a $25 million U.S. facility and, (b) through our wholly ownedCanadian subsidiary, a $35 million Canadian facility.  The amendment terminated the Canadian portion of the facility andmodified certain provisions of the U.S. facility to accommodate the newCanadian credit facility (“Canadian Credit Facility”) discussed below.

 

Availableborrowings under the Credit Facility are determined by (a) a borrowing base,calculated semiannually, which is based principally on the proved reserves ofour oil and gas properties (amended to be $0); and (b) a working capitalborrowing base, calculated monthly, which is based on NGL product accountsreceivable and inventory levels, to a maximum of $20 million ($13.7 million wasavailable as of September 30, 2003). Actual borrowing limits may be less than$60 million, and MarkWest Hydrocarbon may be required to pay down amountsborrowed in excess of their applicable borrowing base, depending on provedreserves for our properties, our working capital and our financialcovenants.  At September 30, 2003,MarkWest Hydrocarbon had outstanding borrowings of $2.0 million under theCredit Facility.

 

The CreditFacility permits us to borrow money using a base rate loan, plus an applicablemargin of 0.375% and 1.375%, or a London Interbank Offered Rate (“LIBOR”) loanoption, plus an applicable margin of between 1.75% and 2.75%, based on acertain debt-to-earnings ratio.  We payfees of between 0.25% and 0.50% per annum on the unused commitment, based onour debt-to-earnings ratio. The Credit Facility matures in August 2004.  For the year ended December 31, 2002, theweighted average interest rate was 4.88%.

 

TheCredit Facility contains various covenants limiting our ability to:

 

•                  Incur indebtedness;

•                  Grant certain liens;

•                  Make certain investments or payments;

•                  Enter into certain leases;

•                  Enter into a merger or consolidation;

•                  Dispose of assets;

•                  Amend or enter into certain agreements;

•                  Conduct preferential transactions with certainaffiliates; and

•                  Pay dividends.

 

TheCredit Facility also contains covenants requiring us to maintain a minimumtangible net worth and meet certain financial ratios, as defined in the CreditFacility. The Credit Facility is secured by a first lien onsubstantially all of our assets, excluding our Partnership subordinated unitsand our interest in the Partnership’s general partner.

 

A new Canadian CreditFacility was entered into by our wholly owned Canadian subsidiary and wasinitially funded on October 6, 2003. Available borrowings under the Canadian Credit Facility are limited tothe lesser of CDN$30 million and the “Borrowing Base” which is determined bythe lender from time to time, and is based principally on the proved reservesof our oil and gas properties.

 

The CanadianCredit Facility permits us to borrow money using a prime rate loan, plus anapplicable margin of 0.25% and 1.50%, or a base rate option, plus an applicablemargin of between 1.50% and 2.75%, based on a certain debt-to-cash flowratio.  We pay a fee of 0.25% per annumon the unused commitment.  The CanadianCredit Facility is subject to annual review, with the first review scheduledfor May 31, 2004.

 

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TheCanadian Credit Facility contains various covenants limiting our ability to:

 

•                  Incur indebtedness;

•                  Grant certain liens;

•                  Enter into a merger or consolidation;

•                  Dispose of assets or move assets outside Alberta,Saskatchewan, British Columbia or Manitoba; and

•                  Pay dividends or repay shareholder loans.

 

TheCanadian Credit Facility also contains covenants requiring us to meet certainfinancial ratios, as defined in the Canadian Credit Facility. TheCanadian Credit Facility is secured by a first lien on substantially all of theassets of MarkWest Resources Canada Corp.

 

***MarkWest Energy Partners Signs Agreement to Acquire ShellCrude Pipeline***

 

On November 7, 2003, MarkWest Energy Partners enteredinto a Purchase and Sale Agreement with Shell Pipeline Company LP and otherShell subsidiaries, for the acquisition of Shell’s Michigan Crude GatheringPipeline assets for approximately $21 million. The acquisition will be financedutilizing MarkWest Energy Partners’ existing credit facility, which it anticipatesexpanding in conjunction with the acquisition.

 

Thecrude gathering assets, located in northern Michigan, are comprised ofapproximately 250 miles of pipelines, 4 truck unloading stations, associatedterminals and tank facilities.  Thesystem is a common carrier Michigan intrastate pipeline and gathersapproximately 16,000 barrels per day of light crude oil from wells throughoutMichigan.  The oil is transported for afee to the Lewiston station where it is batch injected into the Enbridge LakeheadPipeline, which then transports the oil to refineries in Sarnia Ontario,Canada.  The pipeline provides theproducers in Michigan an alternative to trucking the crude to the Sarniarefinery complex.

 

***MarkWest Hydrocarbon Signs Agreement to Sell CanadianSubsidiary***

 

On November 12,2003, MarkWest Hydrocarbon announced we had entered into a Purchase and SaleAgreement with Advantage Energy Income Fund to sell our wholly ownedsubsidiary, MarkWest Resources Canada Corp., for cash consideration ofCDN$102.5 million, less debt and other liabilities assumed by Advantage EnergyIncome Fund. The sale price may be increased by up to an additional CDN$2.5million if certain lands are retained through additional drilling prior toDecember 31, 2003.

 

We continue toevaluate options for our wholly owned subsidiary, MarkWest Canadian MidstreamServices Inc., which holds natural gas exploration assets located in theBigstone-Berland River area of west-central Alberta.

 

We plan to usethe net proceeds from the sale to retire debt outstanding under our existingbank revolving credit facility and for general corporate purposes.

 

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

 

**Forward-LookingInformation**

 

Statements included in this Management’sDiscussion and Analysis of Financial Condition and Results of Operations thatare not historical facts are forward-looking statements within the meaning ofSection 27A of the Securities Act of 1933, as amended, and Section 21E of theSecurities and Exchange Act of 1934, as amended. We use words such as “may,”“believe,” “estimate,” “expect,” “plan,” “intend,” “project,” “anticipate,” andsimilar expressions 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

 

Important factors that could cause ouractual results of operations or our actual financial condition to differinclude, 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

 

13

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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.

 

**Sale ofSan Juan Basin Properties**

 

During thethird quarter of 2003, we completed the sales of the remainder of our San JuanBasin oil and gas properties to certain third parties for approximately $6.1million, net of anticipated transaction costs and closing adjustments.Previously, we closed on the sale of the majority of our San Juan Basinproperties in the second quarter of 2003. We recognized a net pretax gain of$3.3 million on the sales completed during the third quarter. The net proceedsfrom the sales are being used for working capital and general corporatepurposes.

 

**Terminal Dispositions**

 

Our Board of Directorshas approved a plan to sell any of our three NGL product terminals, which areconsidered to be non-strategic assets. On July 15, 2003, we sold our Lordstown,Ohio terminal to a third party for approximately $0.7 million, including $0.2million for on-hand inventory. On September 2, 2003, we sold our Lynchburg,Virginia terminal to a third party for approximately $1.6 million plus on-handinventory. As a result of the two sales, we incurred a loss of less than $0.1million.

 

**Pinnacle Acquisition**

 

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

 

The acquisition wasaccomplished through a merger under Texas law of the Sellers and four newlyformed wholly owned subsidiaries of MarkWest Energy Partners as buyers. In themerger, most of the assets and liabilities of the Sellers were allocated to theMarkWest Energy Partners entities, and all entities survived the merger. Theassets acquired from the Sellers, primarily located in the State of Texas, withthe balance located in New Mexico, Louisiana, Mississippi and Kansas, arecomprised of three lateral natural gas pipelines and twenty gathering systems.The three lateral natural gas pipelines consist of approximately 67 miles ofpipe and transport up to 1.1 Bcf/day under fixed-fee contracts to power plants.The twenty gathering systems gather more than 44 MMcf/d.

 

##### **Lubbock Pipeline Acquisition**

 

On September 2, 2003,through its wholly owned subsidiary, MarkWest Pinnacle L.P., MarkWest EnergyPartners completed the acquisition of a 68-mile intrastate gas transmissionpipeline near Lubbock, Texas from a subsidiary of ConocoPhillips forapproximately $12.2 million. The transaction was financed through borrowingsunder MarkWest Energy Partners’ existing credit facility. The acquisition wasaccounted for as a purchase business combination.

 

##### **Retirement of President and Chief Executive Officerand Appointment of Successor**

 

The Boards ofDirectors of MarkWest Hydrocarbon and of the general partner of MarkWest EnergyPartners announced on October 23, 2003, that John M. Fox, the current Chairman,President and Chief Executive Officer of MarkWest Hydrocarbon and the generalpartner of MarkWest Energy Partners, has advised them he will retire as ChiefExecutive Officer effective December 31, 2003. (The general partner of MarkWestEnergy Partners is a consolidated subsidiary of MarkWest Hydrocarbon.) As partof the management transition, the Boards also announced the resignation of Mr.Fox as President effective November 1, 2003, and the appointment of Frank M.Semple as President as of such date. To facilitate an orderly transition, Mr.Fox will continue in his role as Chief Executive Officer during the remainderof the calendar year, after which time Mr. Semple will also assume the positionof Chief Executive Officer.

 

Mr. Fox willremain a Director and Chairman of the Board of both MarkWest Hydrocarbon andthe general partner of MarkWest Energy Partners. Mr. Fox founded MarkWestHydrocarbon and has served as its President,

 

14

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Chief Executive Officer and Chairman of the Boardsince its inception in April 1988. Mr. Fox has served in the same capacitiesfor the general partner of MarkWest Energy Partners since May 2002.

 

Prior to acceptinghis appointment to MarkWest Hydrocarbon and the general partner of MarkWestEnergy Partners, Mr. Semple served as Chief Operating Officer of WilTelCommunications, formerly Williams Communications, a $1.5 billion revenue,2,500-employee telecommunications company based in Tulsa, Oklahoma. Precedingthat, he held the position of Senior Vice President/General Manager of WilliamsNatural Gas from 1995 to 1997 as well as Vice President of Marketing and VicePresident of Operations and Engineering for Northwest Pipeline and Director ofProduct Movements and Division Manager for Williams Pipeline during his 22-yearcareer with the Williams Companies. During his tenure at WilliamsCommunications, he served on the board of directors for PowerTel Communicationsand the Competitive Telecommunications Association. He currently serves on theboard of directors for the Tulsa Zoo and Children’s Medical Center. Mr. Sempleholds a bachelor’s degree in mechanical engineering from the United StatesNaval Academy. He also completed the Program for Management Development atHarvard University.

 

##### **MarkWest Energy Partners Signs Agreement to AcquireShell Crude Pipeline**

 

On November 7, 2003, MarkWest Energy Partners enteredinto a Purchase and Sale Agreement with Shell Pipeline Company LP and otherShell subsidiaries, for the acquisition of Shell’s Michigan Crude GatheringPipeline assets for approximately $21 million. The acquisition will be financedutilizing MarkWest Energy Partners’ existing credit facility, which it anticipatesexpanding in conjunction with the acquisition.

 

Thecrude gathering assets, located in northern Michigan, are comprised ofapproximately 250 miles of pipelines, 4 truck unloading stations, associatedterminals and tank facilities.  Thesystem is a common carrier Michigan intrastate pipeline and gathersapproximately 16,000 barrels per day of light crude oil from wells throughoutMichigan.  The oil is transported for afee to the Lewiston station where it is batch injected into the EnbridgeLakehead Pipeline, which then transports the oil to refineries in SarniaOntario, Canada.  The pipeline providesthe producers in Michigan an alternative to trucking the crude to the Sarniarefinery complex.

 

**MarkWestHydrocarbon Signs Agreement to Sell Canadian Subsidiary**

 

During the third quarterof 2003, our Board of Directors approved a plan to sell our Canadian oil andgas properties. Management also intends to dispose of our remaining U.S. andCanadian oil and gas properties within the next year as we discontinue ourexploration and production business.

 

On November 12,2003, MarkWest Hydrocarbon announced we had entered into a Purchase and SaleAgreement with Advantage Energy Income Fund to sell our wholly ownedsubsidiary, MarkWest Resources Canada Corp., for cash consideration ofCDN$102.5 million, less debt and other liabilities assumed by Advantage EnergyIncome Fund. The sale price may be increased by up to an additional CDN$2.5million if certain lands are retained through additional drilling prior toDecember 31, 2003.

 

We continue toevaluate options for our wholly owned subsidiary, MarkWest Canadian MidstreamServices Inc., which holds natural gas exploration assets located in theBigstone-Berland River area of west-central Alberta.

 

We plan to usethe net proceeds from the sale to retire debt outstanding under our existingbank revolving credit facility and for general corporate purposes.

 

15

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**Results of Operations**

*Operating Data*
|                                               |   | **Three  Months Ended September 30,** |   | **Nine  Months Ended September 30,** |   |
|----------------------------------------------------|--------|---------------------------------------|--------|--------------------------------------|--------|
|                                               |   | **2003**                              |   | **2002**                             |   | **% Change** |   | **2003** |   | **2002** |   | **% Change** |   |
|                                               |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| **Gathering,  processing and marketing**           |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| Appalachia:                                        |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| NGL product production—Siloam plant (gallons) |   | 47,000,000                            |   | 44,600,000                           |   | 5 | % | 122,700,000 |   | 129,200,000 |   | (5 | )% |
| NGL product sales—Siloam plant (gallons)      |   | 40,800,000                            |   | 37,200,000                           |   | 10 | % | 125,700,000 |   | 128,600,000 |   | (2 | )% |
|                                               |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| Southwest(1)                                       |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| Pipeline throughput (Mcf/d)                        |   | 59,000                                |   | —                               |   | NM |   | 51,000 |   | — |   | NM |   |
|                                               |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| Michigan:                                          |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| Pipeline throughput (Mcf/d)                        |   | 17,300                                |   | 16,900                               |   | 2 | % | 15,700 |   | 13,400 |   | 17 | % |
| NGL product sales (gallons)                        |   | 3,982,000                             |   | 3,212,000                            |   | 24 | % | 9,112,000 |   | 8,081,000 |   | 13 | % |
|                                               |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| **Exploration  and production**                    |   |                                  |   |                                 |   |   |   |   |   |   |   |   |   |
| Natural gas produced (Mcfe/d)                      |   | 20,900                                |   | 31,100                               |   | (33 | )% | 24,400 |   | 29,800 |   | (18 | )% |

*** ***

----

***NM***– Not meaningful

(1)  Acquired March 28, 2003, and September2, 2003, MarkWest Energy Partners’ Southwest assets are located primarily inTexas and four surrounding states.

 

***Three Months EndedSeptember 30, 2003 Compared to the Three Months Ended September 30, 2002***

## ** **

*Revenue.* Revenuewas $48.2 million for the three months ended September 30, 2003, compared to$29.5 million for the three months ended September 30, 2002, an increaseof $18.9 million, or 63%. The Pinnacle Acquisition increased revenue $15.3million. Higher NGL product sales prices and volumes from our Appalachianoperations were partially offset by a reduction in gas marketing revenues, aresult of reduced volumes sold.  Thirdquarter 2002 results include a $1.8 million non-cash hedging ineffectivenesscharge.

 

*Purchased product costs.*  Purchased product costs were $44.5 millionfor the three months ended September 30, 2003, compared to $26.3 million forthe three months ended September 30, 2002, an increase of $18.2 million, or69%. The Pinnacle Acquisition increased purchased product costs $12.1 million,partially offset by a reduction in gas marketing purchased products costs of$4.1 million, a result of reduced volumes sold. Increased product costs andsales volumes from our Appalachian operations increased purchased product costs$8.8 million.

 

*Facility expenses.*  Facility expenses were $5.3 million for the threemonths ended September 30, 2003, compared to $3.8 million for the three monthsended September 30, 2002, an increase of $1.6 million, or 41%. The PinnacleAcquisition and higher fuel costs in our Appalachian operations primarilycaused the increase.

 

*Selling,*g*eneral andadministrative expenses.* Selling, general and administrative expenses were $3.4 million for thethree months ended September 30, 2003, compared to $2.3 million for the threemonths ended September 30, 2002, an increase of $1.1 million, or 48%.  The increase is principally attributable tothe Pinnacle Acquisition, increased insurance costs and incremental costsassociated with operating MarkWest Energy Partners as a public company.

 

*Depreciation.*  Depreciation was $2.2 million for the threemonths ended September 30, 2003, compared to $1.3 million, for the three monthsended September 30, 2002, an increase of $0.9 million, or 65%. Depreciationincreased primarily due to the Pinnacle Acquisition.

 

*Interest expense.*  Interest expense was $1.1 million for thethree months ended September 30, 2003, compared to $0.8 million for the threemonths ended September 30, 2002, an increase of  $0.4 million, or 51%. Interest expense increased due to a largeraverage outstanding debt balance, primarily a function of the financing ofMarkWest Energy Partners’ 2003 acquisitions.

 

16

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*Minorityinterest in net income of consolidated subsidiary.*Thisrepresents the minority interest (i.e., non-MarkWest Hydrocarbon) ownership inthe net income of MarkWest Energy Partners, which completed its initial publicoffering in May 2002.

 

*Discontinuedoperations.*We decided to exit the exploration and productionbusiness during the third quarter of 2003. Consequently, we have aggregated theresults of operations, net of tax, from that business for separate disclosurein accordance with SFAS No. 144. We also sold the remaining portion of our SanJuan Basin properties during the third quarter of 2003.

 

***Nine Months Ended September30, 2003 Compared to the Nine Months Ended September 30, 2002***

 

*Revenue.* Revenuewas $146.8 million for the nine months ended September 30, 2003, compared to$105.4 million for the nine months ended September 30, 2002, an increaseof $41.3 million, or 39%. Revenue was higher in 2003 than in 2002 primarily dueto:

 

•                  The Pinnacle Acquisition added $32.8million.

•                  Increased NGL product sales pricesoffset modest volume decreases in Appalachia adding $28.5 million in revenuepartially offset by $11.2 million of increased hedging losses in 2003.

•                  Gas marketing volumes declinedprimarily due to reduced volumes sold decreasing revenue $12.6 million.

•                  $1.7 million in non-cash hedgingineffectiveness charges in 2002 have substantially reversed during 2003.

 

*Purchased product costs.*  Purchased product costs were $134.9 millionfor the nine months ended September 30, 2003, compared to $86.7 million for thenine months ended September 30, 2002, an increase of $48.2 million, or 54%.Purchased product costs were higher in 2003 primarily due to:

 

•                  The Pinnacle Acquisition added $26.6million.

•                  Increased natural gas costs offsetmodest volume decreases in Appalachia adding $27.3 million in purchased productcosts.

•                  Gas marketing volumes declinedprimarily due to reduced volumes sold decreasing purchased product costs $10.5million.

 

*Facility expenses.*  Facility expenses were $14.4 millionfor the nine months ended September 30, 2003, compared to $11.9 millionfor the nine months ended September 30, 2002, an increase of $2.4 million, or20%. Facility operating expenses increased primarily due to the PinnacleAcquisition and higher fuel costs in Appalachia.

 

*Selling,*g*eneral andadministrative expenses.* Selling, general and administrative expenses were $9.1 million for thenine months ended September 30, 2003, compared to $6.5 million for the ninemonths ended September 30, 2002, an increase of $2.5 million, or 39%. Theincrease is principally attributable to the Pinnacle Acquisition, increasedinsurance costs and incremental costs associated with operating MarkWest EnergyPartners as a public company.

 

*Depreciation.*Depreciation was $5.8 million for the nine months ended September 30,2003, compared to $4.2 million, for the nine months ended September 30, 2002,an increase of $1.5 million, or 36%. Depreciation increased primarily due to the Pinnacle Acquisition.

 

*Interest expense.*  Interest expense was $4.2 million for boththe nine months ended September 30, 2003, compared to $3.0 million for the ninemonths ended September 30, 2002, an increase of $1.2 million, or 42%. Thesettlement of interest rate swaps during the second quarter of 2003 increasedinterest expense $0.6 million. The remainder of the increase is principallyattributable to an increase in the average outstanding debt balance during thethird quarter of 2003, a result of financing MarkWest Energy Partners’ 2003acquisitions.

 

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

 

17

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*Minorityinterest in net income of consolidated subsidiary.*Thisrepresents the minority interest (i.e., non-MarkWest Hydrocarbon) ownership inthe net income of MarkWest Energy Partners, which completed its initial publicoffering in May 2002.

 

*Discontinuedoperations*. We decided to exit theexploration and production business during the third quarter of 2003.Consequently, we have aggregated the results of operations, net of tax, fromthat business for separate disclosure in accordance with SFAS No. 144. We alsosold our San Juan Basin properties during the second and third quarters of2003.

 

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

 

**Liquidity and Capital Resources**

 

MarkWestHydrocarbon’s primary sources of liquidity are cash flow generated fromoperations and borrowings under our credit facility. From time to time, oursources of funds are supplemented with proceeds from sales of assets andoperating leases used to finance support equipment.

 

MarkWestHydrocarbon’s cash flow generated from operations is subject to volatility inenergy prices, especially prices for NGLs and natural gas. Our cash flow isenhanced in periods when the prices received for NGLs are high relative to theprice of natural gas we purchase to satisfy our “keep-whole” contractualarrangements in Appalachia, and is reduced in periods when the prices receivedfor NGLs are low relative to the price of natural gas we purchase to satisfysuch contractual arrangements. Under “keep-whole” contracts, we retain and sellthe NGLs produced in our processing operations for third-party producers, andthen reimburse or “keep whole” the producers for the Btu content of the NGLsremoved through the re-delivery to the producers of an equivalent amount (on aBtu basis) of dry natural gas. 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. Periodically, when naturalgas becomes more expensive, on a Btu equivalent basis, than NGL products, thecost of keeping the producer “whole” can result in operating losses.

 

Toward the endof the first quarter of 2003, natural gas prices began to be unusually highcompared to NGL prices.  This unusualdisparity in prices reduced our internally generated cash flows through thesecond quarter and into the third quarter of 2003.  However, this disparity in prices has substantially reversedbeginning in the third quarter and is expected to remain near historical levelsthrough the remainder of 2003.

 

To combat the reductionin cash flows and otherwise bolster our liquidity, we sold our San Juan Basinoil and gas properties during the second and third quarters of 2003 forapproximately $55.9 million, net of anticipated transaction costs and closingadjustments. We recognized a net pretax gain of approximately $23.0 million onthe sales. The proceeds from the sale were used to repay debt outstanding underour existing credit facility in the amount of approximately $42.6 million.  The remaining proceeds are being used forgeneral corporate purposes. Additionally, on November 12, 2003, we announcedthat we have entered into an agreement with a third party to sell one of ourCanadian subsidiaries, which owns most of our Canadian oil and gas properties.

 

Almost all of our capital expenditures arediscretionary.  We continue to manageour future capital expenditures to match available cash flows from operations.As of September 30, 2003, MarkWest Hydrocarbon has borrowed $19.1 million ofthe approximate $31.7 million available credit under our credit facility.

 

For MarkWest EnergyPartners, future acquisitions or projects are expected to be financed through acombination of debt and issuance of additional units, as is common practicewith master limited partnerships. The Pinnacle Acquisition and the LubbockPipeline Acquisition were financed under MarkWest Energy Partners’ creditfacility, which was expanded by $15 million on March 28, 2003. Additionally,MarkWest Energy Partners sold 375,000 common units in two installments at aprice of $26.23 per unit in a private placement to certain accreditedinvestors. These sales grossed $9.8 million and were completed July 10, 2003.As of September 30, 2003, MarkWest Energy Partners has borrowed $61.3 millionof the $75 million available credit under its $75 million credit facility.

 

18

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MarkWest Hydrocarbon(exclusive of MarkWest Energy Partners) forecasts a baseline capital budget of$3.6 million for the remainder of 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.

 

# ***MarkWestEnergy Partners’ budget for pipelineconnections and other system improvements related to the Pinnacle Acquisitionfor the remainder of 2003 is $0.5 million. Under certain circumstances, theparty from which MarkWest Energy Partners acquired the Pinnacle Acquisition hasthe right to require MarkWest Energy Partners to purchase an additional lateralpipeline for up to $2.5 million.***

 

*Cash Flows*

 

Net cash provided by operatingactivities was $3.2 million and  $33.9million for the nine months ended September 30, 2003 and 2002, respectively.Net cash provided by operating activities decreased during the first ninemonths of 2003 primarily due to losses from our keep-whole contract basedbusiness.

 

Netcash used in investing activities was $17.8 million and $25.1 million forthe nine months ended September 30, 2003 and 2002, respectively. Net cash usedin investing activities was lower in 2003 due to the proceeds from the sale ofour San Juan Basin properties, net of the Pinnacle Acquisition and the LubbockPipeline Acquisition.

 

Net cash provided by financing activities was $15.7 million during thefirst nine months of 2003. Net cash used in financing activities was $9.2million during the first nine months of 2002. In 2003, we had net borrowings, primarily due to the financing of thePinnacle Acquisition and the Lubbock Pipeline Acquisition. Additionally,MarkWest Energy Partners, raised capital via a private placement of 375,000 ofits common units.

 

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

 

***Commodity PriceRisk***

 

*Overview*

 

Our business bothproduces products—natural gas and NGLs—and provides services—gathering,processing, transportation and marketing of natural gas and the transportation,fractionation and storage and marketing of NGLs. Our products are commoditiesthat subject us to price risk. Commodity prices are often subject to 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 riskmanagement objective is to manage our price risk, thereby reducing volatilityin our cash flows. Our hedging approach uses a statistical method that analyzesmomentum and average pricing over time, and various fundamental data such asindustry inventories, industry production, demand and weather. Hedging levelsmay increase with capital commitments and debt levels and when above-averagemargins exist. We maintain a committee, including members of senior management,which oversees all hedging activity.

 

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

 

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

 

The use of financialinstruments may expose us to the risk of financial loss in certaincircumstances, including instances when (i) sales volumes may be less thanexpected requiring market purchases to meet

 

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commitments, (ii) our OTC counterparties could fail to purchase ordeliver the contracted quantities of natural gas, NGL, or crude oil orotherwise fail to perform, and (iii) when the trading relationship betweencrude oil and NGL products is outside historical levels. To the extent that weengage in hedging activities, we may be prevented from realizing the benefitsof favorable price changes in the physical market. However, we may be similarlyinsulated against decreases in such prices.

 

*Types of Price Risk*

 

Withinour exploration and production segment, our revenues are subject to natural gasprice risk. (We sold substantially all of our U. S. reserves during the secondand third quarters. Additionally, our Board of Directors has approved a plan tosell all or part of our Canadian oil and gas properties.)

 

Withinour NGL marketing segment, our price risk varies by contract as well as by spotmarket prices. Our Appalachian producers compensate us for providing midstreamservices 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 Btu basis)of dry natural gas. Keep-whole contracts therefore expose us to NGL productprice risk (on the sales side) and natural gas price risk (on the purchase orreimbursement side). Generally, the value of the NGLs extracted is greater thanthe cost of replacing those Btus with dry gas, resulting in positive operatingmargins under these contracts. In the event natural gas becomes more expensive,on a Btu equivalent basis, than NGL products, the cost of keeping the producer“whole” results in operating losses. The spread between the NGL product salesprice and the purchase price of natural gas with an equivalent Btu content iscalled 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 its gatheringsystems in Texas and four surrounding states, many under percent-of-proceeds orpercent-of-index contracts.

 

*Basis Risk*

 

Tothe extent our natural gas production offsets 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 exposedto basis risk. Our basis risk for natural gas stems from the geographic pricedifferentials between our exploration and production sales location (Alberta,Canada) and hedging contract delivery location (NYMEX) and our marketingpurchase location (Appalachia) and NYMEX. At times, we hedge our basis risk for natural gas.

 

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

 
|    |   | **Table  I**Hedged Natural Gas Basis** |   |
|---------|--------|----------------------------------------|--------|
|    |   | **Year  Ending  December 31, 2003**    |   |
| MMBtu   |   | 370,000                                |   |
| $/MMBtu |   | $                                      | (0.71  | ) |
|         |        |                                        |        |  |

 

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We are generally unableto hedge our basis risk for NGL products. We have two different types of NGLproduct basis risk. First, NGL product basis risk stems from the geographicprice differentials between our sales locations and hedging contract deliverylocations. We cannot hedge our geographic basis risk because there are noreadily available products or markets. Second, NGL product basis risk alsoresults from the difference in relative price movements between crude oil andNGL products. We may use crude oil, instead of NGL products, in our hedgesbecause the NGL hedge products and markets are limited. Crude oil is highlycorrelated with certain NGL products.

 

*Natural Gas Price Risk*

 

Weare an overall net consumer of natural gas as our keep-whole contractualrequirements for purchasing natural gas in Appalachia exceed our natural gasproduction. Consequently, our exploration and production hedges are generallylimited to either (i) obtaining futures prices that our models suggest areoptimal, (ii) realizing the economics of a transaction, like our 2001 Canadianexploration and production acquisition, or (iii) mitigating our basis risk asdescribed above. Generally, we execute our strategy by either entering intofixed-for-float swaps or utilizing costless collars. As of September 30, 2003,we have hedged our Canadian natural gas volumes and prices as follows:

 
|                  |   | **Table II**

**Hedged  Natural Gas Sales** |   |
|-----------------------|--------|---------------------------------------------|--------|
|                  |   | **Year  Ending December 31,**               |   |
|                  |   | **2003**                                    |   | **2004** |   | **2005** |   |
|                  |   |                                        |   |   |   |   |   |
| MMBtu                 |   | 561,000                                     |   | 610,000 |   | — |   |
| $/MMBtu               |   | $                                           | 3.56   |   | $ | 3.19 |   | $ | — |   |
| Henry  Hub Equivalent |   | $                                           | 4.25   |   | $ | 4.08 |   | $ | — |   |

 

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 September30, 2003, MarkWest Energy Partners hedged its Pinnacle natural gas price riskvia swaps as follows:

 
|    |   | **Table III  Hedged Natural Gas Sales** |   |
|---------|--------|-----------------------------------------|--------|
|    |   | **Year  Ending December 31,**           |   |
|    |   | **2003**                                |   | **2004** |   | **2005** |   |
|    |   |                                    |   |   |   |   |   |
| MMBtu   |   | 46,000                                  |   | 183,000 |   | 183,000 |   |
| $/MMBtu |   | $                                       | 5.09   |   | $ | 4.57 |   | $ | 4.26 |   |
|         |        |                                         |        |  |  |  |  |  |  |  |

 

As of September 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                         |   | 92,000                                 |   | 366,000 |   | — |   |
| Floor  strike price ($/MMBtu) |   | $                                      | 4.50   |   | $ | 4.00 |   | $ | — |   |
|                               |        |                                        |        |  |  |  |  |  |  |  |

 

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*NGL Product Price Risk*

 

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

 
|                                                         |   | **Table V  Hedged Sales Price for NGL Products** |   |
|--------------------------------------------------------------|--------|--------------------------------------------------|--------|
|                                                         |   | **Year Ending December 31,**                     |   |
|                                                         |   | **2003**                                         |   | **2004** |   |
| **MarkWest Hydrocarbon, Inc.**                               |   |                                             |   |   |   |
| NGL Volumes Hedged Using Crude Oil                           |   |                                             |   |   |   |
| NGL gallons                                                  |   | 13,455,000                                       |   | 10,135,000 |   |
| NGL sales prices per gallon                                  |   | $                                                | 0.46   |   | $ | 0.53 |   |
|                                                         |   |                                             |   |   |   |
| **MarkWest Energy Partners, L.P.**                           |   |                                             |   |   |   |
| Butanes and  Natural Gasoline Volumes Hedged Using Crude Oil |   |                                             |   |   |   |
| NGL gallons                                                  |   | 869,000                                          |   | — |   |
| NGL sales price per gallon                                   |   | $                                                | 0.50   |   | — |   |
| Propane Volumes Hedged Using Propane                         |   |                                             |   |   |   |
| NGL gallons                                                  |   | 315,000                                          |   | — |   |
| NGL sales price per gallon                                   |   | $                                                | 0.41   |   | — |   |
| Total NGL Volumes Hedged                                     |   |                                             |   |   |   |
| NGL gallons                                                  |   | 1,184,000                                        |   | — |   |
| NGL sales price per gallon                                   |   | $                                                | 0.48   |   | — |   |
|                                                              |        |                                                  |        |  |  |  |  |

 

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.

 

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 extent ourAppalachian natural gas purchase requirements exceed our E&P natural gasproduction, we are simultaneously subject to NGL price risk on the sales sideand 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 September 30, 2003, we had no such hedges in place.

 

***Interest Rate Risk***

 

*MarkWestHydrocarbon, Inc.*

 

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

 

*MarkWestEnergy Partners, L.P.*

 

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

 

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

 

We maintain disclosurecontrols and procedures that are designed to ensure that information requiredto be disclosed by us in the reports that we file or submit to the Securitiesand Exchange Commission under the Securities Exchange Act of 1934, as amended,is recorded, processed, summarized and reported within the time periodsspecified by the Commission’s rules and forms, and that information isaccumulated and communicated to our management, including our principalexecutive and principal financial officers (who we refer to in this periodicreport as our Certifying Officers), as appropriate to allow timely decisionsregarding required disclosure. Our management evaluated, with the participationof our Certifying Officers, the effectiveness of our disclosure controls andprocedures as of September 30, 2003, pursuant to Rule 13a-15(b) under theExchange Act. Based upon that evaluation, our Certifying Officers concludedthat as of September 30, 2003, our disclosure controls and procedures were effective.

 

There were no changes inour internal control over financial reporting that occurred during our mostrecently completed fiscal quarter that have materially affected, or arereasonably like to materially affect, our internal control over financial reporting.

 

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#####  

##### **PART II OTHER INFORMATION**

 

**Item 1.  Legal Proceedings**

 

Pursuant to theintroductory instruction Part II (Other Information) of Form 10-Q, theinformation required to be furnished by us under this part II, Item 1 (LegalProceedings) is incorporated by reference to Note 11 (Commitments andContingencies) of our Notes to Unaudited Consolidated Financial Statementsincluded in Part 1, Item 1 (Financial Statements) of this report on Form 10-Q.

 

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

 

(a)           Exhibits

 

10.1         Purchaseand Sale Agreement, dated as of June 5, 2003, by and among MarkWestHydrocarbon, Inc., MarkWest Resources, Inc. and XTO Energy Inc. (incorporatedby reference to Exhibit 10 to the MarkWest Hydrocarbon’s current report on Form8-K filed with the SEC on July 15, 2003)

 

10.2         Purchase and SaleAgreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC,Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P.(incorporated by reference to Exhibit 2.1 to MarkWest Energy Partners’ currentreport on Form 8-K filed with the SEC on September 17, 2003)

 

11            Statement regardingcomputation of earnings per share.

 

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

 

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

 

32.1         Certificationof Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as AdoptedPursuant to Section 906 of the Sarbanes-OxleyAct of 2002.

 

32.2         Certificationof Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as AdoptedPursuant to Section    906 of theSarbanes-Oxley Act of 2002.

 

(b)           Reports on Form 8-K

 

A current report on Form8-K was filed with the SEC under items 5 and 7 of Form 8-K on July 15, 2003,announcing the declaration by our Board of Directors of a stock dividend of oneshare of MarkWest Hydrocarbon’s common stock for each ten shares of commonstock held by MarkWest Hydrocarbon’s common stockholders of record as of theclose of business on July 31, 2003.

 

Acurrent report on Form 8-K was filed with the SEC under items 2 and 7 of Form8-K July 15, 2003, announcing the completion of our sale of the majority of ourSan Juan Basin oil and gas properties to XTO Energy Inc. for approximately$50.8 million in cash.

 

Acurrent report on Form 8-K was filed with the SEC under items 5 and 7 of Form8-K on August 4, 2003, announcing our consolidated subsidiary, MarkWest EnergyPartners, through its subsidiary, MarkWest Pinnacle L.P., had entered into aPurchase and Sale Agreement with Power-Tex Joint Venture, a subsidiary ofConocoPhillips, to acquire an intrastate gas transmission pipeline nearLubbock, Texas for approximately $12 million.

 

Acurrent report on Form 8-K was furnished with the SEC under items 7 and 12 ofForm 8-K on August 13, 2003, concerning our second quarter 2003 earningsrelease dated August 13, 2003.

 

Anamended current report on Form 8-K/A was filed with the SEC under items 2 and 7of Form 8-K on August 26, 2003, announcing that our consolidated subsidiary,MarkWest Energy Partners, L.P., completed its acquisition of Pinnacle NaturalGas Company and certain affiliates on March 28, 2003. The amended report includedthe audited

 

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financialstatements of PNG Corporation and Subsidiaries.

 

Acurrent report on Form 8-K was filed with the SEC under items 2 and 7 of Form8-K on September 17, 2003, announcing our consolidated subsidiary, MarkWestEnergy Partners, through its subsidiary, MarkWest Pinnacle L.P., completed itsacquisition of an intrastate gas transmission pipeline near Lubbock, Texas,from Power-Tex Joint Venture, a subsidiary of ConocoPhillips, and certain ofits affiliates, for approximately $12 million in cash.

 

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**SIGNATURE**

 

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

 
|                          |   | MarkWest Hydrocarbon, Inc.                                                                            |
|-------------------------------|--------|-------------------------------------------------------------------------------------------------------|
|                          |   | (Registrant)                                                                                          |   |
|                          |   |                                                                                                  |   |
|                          |   |                                                                                                  |
| Date:  November 13, 2003 | By:    | /s/ Donald C. Heppermann                                                                              |   |
|                          |   |                                                                                                  |
|                          |   | Donald C. Heppermann                                                                                  |
|                          |   | Senior Vice President Finance,  Chief Financial Officer and  Secretary (Principal Financial  Officer) |

 

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**EXHIBITINDEX**

 
| 10.1 |   | Purchase and Sale  Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc.,  MarkWest Resources, Inc. and XTO Energy Inc. (incorporated by reference to  Exhibit 10 to the MarkWest Hydrocarbon’s current report on Form 8-K filed  with the SEC on July 15, 2003)                                           |
|------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.2 |   | Purchase and Sale  Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC,  Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle  L.P. (incorporated by reference to Exhibit 2.1 to MarkWest Energy Partners’  current report on Form 8-K filed with the SEC on September 17, 2003) |
| 11   |   | Statement regarding  computation of earnings per share.                                                                                                                                                                                                                                                                                |
| 31.1 |   | Chief Executive Officer  Certification Pursuant to Section 13a-14 of the Securities Exchange Act.                                                                                                                                                                                                                                      |
| 31.2 |   | Chief Financial Officer  Certification Pursuant to Section 13a-14 of the Securities Exchange Act.                                                                                                                                                                                                                                      |
| 32.1 |   | Certification of Chief  Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                   |
| 32.2 |   | Certification of Chief  Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                   |

 

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