**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

**FORM 10-Q**

 
| ý | **QUARTERLY  REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                                                                      |
|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                              |   |
|   | **For the  quarterly period ended September 30, 2004**                                                                                                                                                                                                                                            |
|   |                                                                                                                                                                                                                                                                                              |   |
|   | **OR**                                                                                                                                                                                                                                                                                            |
|   |                                                                                                                                                                                                                                                                                              |   |
| o      | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                                                                     |
|   |                                                                                                                                                                                                                                                                                              |   |   |
|   | **For the transition period  from                     to                     ** |
|        |                                                                                                                                                                                                                                                                                                   |  |  |

 

**CommissionFile Number 001-14841**

 

**MARKWESTHYDROCARBON, INC.**

**(Exactname of registrant as specified in its charter)**

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

 

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

(Address ofprincipal executive offices)

 

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

 

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

Yes  ý  No  o

 

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

Yes  o  No  ý

 

The registrant had9,769,289 shares of common stock, $.01 per share par value, outstanding as ofOctober 31, 2004.

 

 

----

 
| **PART I—FINANCIAL INFORMATION**                                                               | ** **                                                                                                                     |
|-----------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------|
|                                                                                                |                                                                                                                           |
| Item 1. Consolidated Financial Statements                                                           |                                                                                                                           |
|                                                                                                | Consolidated Balance Sheets  at September 30, 2004 and December 31, 2003                                                       |   |
|                                                                                                | Consolidated  Statements of Operations for the Three and Nine Months Ended September 30,  2004 and 2003                        |   |
|                                                                                                | Consolidated  Statements of Other Comprehensive Income (Loss) for the Three and Nine Months  Ended September 30, 2004 and 2003 |   |
|                                                                                                | Consolidated  Statements of Cash Flows for the Nine Months Ended September 30, 2004 and  2003                                  |   |
|                                                                                                | Consolidated  Statement of Changes in Stockholders’ Equity for the Nine Months Ended  September 30, 2004March 31, 2004    |   |
|                                                                                                | Notes to the  Consolidated Financial Statements                                                                                |   |
|                                                                                                |                                                                                                                           |
| Item 2. Management’s Discussion and Analysis of  Financial Condition and Results of Operations |                                                                                                                           |
| Item  3. Quantitative and Qualitative Disclosures about Market Risk                                 |                                                                                                                           |
| Item 4. Controls and  Procedures                                                                    |                                                                                                                           |
|                                                                                                |                                                                                                                           |
| **PART II-OTHER INFORMATION**                                                                       |                                                                                                                           |
|                                                                                                |                                                                                                                           |
| Item 1. Legal Proceedings                                                                           |                                                                                                                           |
| Item  6. Exhibits                                                                                   |                                                                                                                           |
|                                                                                                |                                                                                                                           |
| **SIGNATURE**                                                                                       |                                                                                                                           |

#### ** **

#### **Glossaryof Terms**

#### ** **

| Bbl/d        | barrels of oil per day                                              |
|--------------|---------------------------------------------------------------------|
| Btu          | British thermal units,  an energy measurement                       |
| Gal/d        | gallons per day                                                     |
| Gross margin | revenues less purchased  product costs                              |
| Mcf          | thousand cubic feet of  natural gas                                 |
| Mcf/d        | thousand cubic feet of  natural gas per day                         |
| MMBtu        | million British thermal  units, an energy measurement               |
| MMcf         | million cubic feet of  natural gas                                  |
| MMcf/d       | million cubic feet of  natural gas per day                          |
| NGL          | natural gas liquids,  such as propane, butanes and natural gasoline |

## ** **

----

 

## **PART I**—FINANCIALINFORMATION

## ** **

## **Item 1**.  Financial Statements

## ** **

**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATED BALANCE SHEETS**

**(UNAUDITED)**

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

 
| ** **                                                                                                                                                | ** ** | **September 30,  2004** | ** ** | **December 31,  2003** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|------------------------|------------|
| **ASSETS**                                                                                                                                                | ** ** | ** **              | ** ** | ** **             | ** ** |
| Current assets:                                                                                                                                           |       |                    |       |                   |       |
| Cash and cash  equivalents                                                                                                                                |       | $                       | 22,258     |                   | $          | 42,144 |   |
| Restricted cash                                                                                                                                           |       | 3,050                   |       | 2,500                  |       |
| Marketable  securities                                                                                                                                    |       | 12,062                  |       | —                 |       |
| Receivables, net  (including related party receivables of $87 and $40, respectively, and  allowance for doubtful accounts of $250 and $120, respectively) |       | 44,162                  |       | 30,750                 |       |
| Inventories                                                                                                                                               |       | 12,450                  |       | 4,815                  |       |
| Prepaid  replacement natural gas                                                                                                                          |       | 13,173                  |       | 5,940                  |       |
| Deferred income  taxes                                                                                                                                    |       | 968                     |       | 603                    |       |
| Other current  assets                                                                                                                                     |       | 3,645                   |       | 503                    |       |
| Total current assets                                                                                                                                      |       | 111,768                 |       | 87,255                 |       |
|                                                                                                                                                      |       |                    |       |                   |       |
| Property, plant  and equipment                                                                                                                            |       | 324,144                 |       | 232,257                |       |
| Less:  accumulated depreciation, depletion, amortization and impairment                                                                                   |       | (55,629                 | )          | (44,134                | )          |
| Total property,  plant and equipment, net                                                                                                                 |       | 268,515                 |       | 188,123                |       |
|                                                                                                                                                      |       |                    |       |                   |       |
| Other assets:                                                                                                                                             |       |                    |       |                   |       |
| Intangible assets, net                                                                                                                                    |       | 165,857                 |       | —                 |       |
| Deferred  financing costs, net                                                                                                                            |       | 7,184                   |       | 3,831                  |       |
| Deferred  offering costs                                                                                                                                  |       | —                  |       | 1,037                  |       |
| Investment in  and advances to equity investee                                                                                                            |       | 200                     |       | 250                    |       |
| Notes receivable  from officers                                                                                                                           |       | 207                     |       | 217                    |       |
| Other assets                                                                                                                                              |       | 42                      |       | —                 |       |
| Total other  assets                                                                                                                                       |       | 173,490                 |       | 5,335                  |       |
|                                                                                                                                                      |       |                    |       |                   |       |
| Total assets                                                                                                                                              |       | $                       | 553,773    |                   | $          | 280,713 |   |
|                                                                                                                                                      |       |                    |       |                   |       |
| **LIABILITIES AND STOCKHOLDERS’ EQUITY**                                                                                                             |       |                    |       |                   |       |
|                                                                                                                                                      |       |                    |       |                   |       |
| Current  liabilities:                                                                                                                                     |       |                    |       |                   |       |
| Accounts payable  (including related party payables of $32 and $51, respectively)                                                                         |       | $                       | 45,044     |                   | $          | 24,052 |   |
| Accrued  liabilities                                                                                                                                      |       | 20,962                  |       | 16,751                 |       |
| Risk management  liability                                                                                                                                |       | 2,747                   |       | 1,769                  |       |
| Total current  liabilities                                                                                                                                |       | 68,753                  |       | 42,572                 |       |
|                                                                                                                                                      |       |                    |       |                   |       |
| Long-term debt                                                                                                                                            |       | 197,500                 |       | 126,200                |       |
| Deferred income  taxes                                                                                                                                    |       | 8,434                   |       | 6,346                  |       |
| Risk management  liability                                                                                                                                |       | —                  |       | 125                    |       |
| Other long-term  liabilities                                                                                                                              |       | 502                     |       | 504                    |       |
| Non-controlling  interest in consolidated subsidiary                                                                                                      |       | 231,558                 |       | 52,782                 |       |
| Commitments and  contingencies (Note 13)                                                                                                                  |       |                    |       |                   |       |
|                                                                                                                                                      |       |                    |       |                   |       |
| Stockholders’  equity:                                                                                                                               |       |                    |       |                   |       |
| Preferred stock,  par value $0.01, 5,000,000 shares authorized, no shares outstanding                                                                     |       | —                  |       | —                 |       |
| Common stock,  par value $0.01, 20,000,000 shares authorized, 9,834,515 and 9,637,977 shares  issued, respectively                                        |       | 98                      |       | 96                     |       |
| Additional  paid-in capital                                                                                                                               |       | 52,409                  |       | 50,715                 |       |
| Accumulated  earnings (deficit)                                                                                                                           |       | (3,457                  | )          | 3,676                  |       |
| Accumulated  other comprehensive loss, net of tax                                                                                                         |       | (1,585                  | )          | (1,793                 | )          |
| Treasury stock,  65,999 and 75,930 shares, respectively                                                                                                   |       | (439                    | )          | (510                   | )          |
| Total  stockholders’ equity                                                                                                                          |       | 47,026                  |       | 52,184                 |       |
|                                                                                                                                                      |       |                    |       |                   |       |
| Total  liabilities and stockholders’ equity                                                                                                          |       | $                       | 553,773    |                   | $          | 280,713 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

1

----

 

**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS**

**(UNAUDITED)**

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

 
| ** **                                                                                                                                           | ** ** | **Three Months Ended September 30,** | ** ** | **Nine Months Ended September 30,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                                                                           | ** ** | **2004**                             | ** ** | **2003**                            | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Revenues                                                                                                                                             |       | $                                    | 122,938    |                                | $          | 48,228 |   | $ | 304,422 |   | $ | 146,767 |   |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Operating  expenses:                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Purchased  product costs                                                                                                                             |       | 95,128                               |       | 44,521                              |       | 245,715 |   | 134,881 |   |
| Facility  expenses                                                                                                                                   |       | 8,281                                |       | 5,204                               |       | 20,147 |   | 13,983 |   |
| Selling, general  and administrative expenses                                                                                                        |       | 5,966                                |       | 3,549                               |       | 14,712 |   | 9,462 |   |
| Depreciation and  amortization                                                                                                                       |       | 5,975                                |       | 2,220                               |       | 13,385 |   | 5,791 |   |
| Loss on sale of  terminals                                                                                                                           |       | —                               |       | 55                                  |       | — |   | 55 |   |
| Total operating  expenses                                                                                                                            |       | 115,350                              |       | 55,549                              |       | 293,959 |   | 164,172 |   |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Income (loss)  from operations                                                                                                                       |       | 7,588                                |       | (7,321                              | )          | 10,463 |   | (17,405 | ) |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Other income  (expense):                                                                                                                             |       |                                 |       |                                |       |   |   |   |   |
| Interest  expense, net                                                                                                                               |       | (7,002                               | )          | (1,115                              | )          | (9,452 | ) | (4,176 | ) |
| Gain on sale to  related party                                                                                                                       |       | —                               |       | —                              |       | — |   | 188 |   |
| Non-controlling  interest in net income of consolidated subsidiary                                                                                   |       | (210                                 | )          | (1,607                              | )          | (4,452 | ) | (3,342 | ) |
| Other income                                                                                                                                         |       | 553                                  |       | 31                                  |       | 585 |   | 15 |   |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Income (loss)  from continuing operations before income taxes                                                                                        |       | 929                                  |       | (10,012                             | )          | (2,856 | ) | (24,720 | ) |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Provision  (benefit) for income taxes:                                                                                                               |       |                                 |       |                                |       |   |   |   |   |
| Current                                                                                                                                              |       | (2,744                               | )          | —                              |       | (2,744 | ) | — |   |
| Deferred                                                                                                                                             |       | 3,104                                |       | (3,701                              | )          | 1,733 |   | (9,058 | ) |
| Provision  (benefit) for income taxes                                                                                                                |       | 360                                  |       | (3,701                              | )          | (1,011 | ) | (9,058 | ) |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Income (loss)  from continuing operations                                                                                                            |       | 569                                  |       | (6,311                              | )          | (1,845 | ) | (15,662 | ) |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Discontinued  operations:                                                                                                                            |       |                                 |       |                                |       |   |   |   |   |
| Income (loss)  from discontinued exploration and production operations (net of income taxes  of $0, $196, $0, and $720, respectively)                |       | —                               |       | (1,260                              | )          | — |   | 2,788 |   |
| Gain from  disposal of discontinued exploration and production operations (less  applicable income taxes of $0, $6,182, $0 and $8,173, respectively) |       | —                               |       | 593                                 |       | — |   | 14,862 |   |
| Income (loss)  from discontinued operations                                                                                                          |       | —                               |       | (667                                | )          | — |   | 17,650 |   |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Income (loss)  before cumulative effect of accounting change                                                                                         |       | 569                                  |       | (6,978                              | )          | (1,845 | ) | 1,988 |   |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Cumulative  effect of change in accounting for asset retirement obligations, net of tax                                                              |       | —                               |       | —                              |       | — |   | (29 | ) |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Net income  (loss)                                                                                                                                   |       | $                                    | 569        |                                | $          | (6,978 | ) | $ | (1,845 | ) | $ | 1,959 |   |
|                                                                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Income (loss)  from continuing operations per share:                                                                                                 |       |                                 |       |                                |       |   |   |   |   |
| Basic                                                                                                                                                |       | $                                    | 0.06       |                                | $          | (0.67 | ) | $ | (0.19 | ) | $ | (1.67 | ) |
| Diluted                                                                                                                                              |       | $                                    | 0.06       |                                | $          | (0.67 | ) | $ | (0.19 | ) | $ | (1.67 | ) |
| Net income  (loss) per share:                                                                                                                        |       |                                 |       |                                |       |   |   |   |   |
| Basic                                                                                                                                                |       | $                                    | 0.06       |                                | $          | (0.74 | ) | $ | (0.19 | ) | $ | 0.21 |   |
| Diluted                                                                                                                                              |       | $                                    | 0.06       |                                | $          | (0.74 | ) | $ | (0.19 | ) | $ | 0.21 |   |
| Weighted average  number of outstanding shares of common stock:                                                                                      |       |                                 |       |                                |       |   |   |   |   |
| Basic                                                                                                                                                |       | 9,760                                |       | 9,378                               |       | 9,695 |   | 9,364 |   |
| Diluted                                                                                                                                              |       | 9,818                                |       | 9,400                               |       | 9,741 |   | 9,380 |   |
| Cash dividend  per common share                                                                                                                      |       | $                                    | 0.025      |                                | $          | — |   | $ | 0.55 |   | $ | — |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

2

----

 

**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATEDSTATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)**

**(UNAUDITED)**

**(inthousands)**

 
| ** **                                      | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------------------------|------------|---------------------------------------|------------|--------------------------------------|------------|
| ** **                                      | ** ** | **2004**                              | ** ** | **2003**                             | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                            |       |                                  |       |                                 |       |   |   |   |   |
| Net income  (loss)                              |       | $                                     | 569        |                                 | $          | (6,978 | ) | $ | (1,845 | ) | $ | 1,959 |   |
|                                            |       |                                  |       |                                 |       |   |   |   |   |
| Other  comprehensive income (loss), net of tax: |       |                                  |       |                                 |       |   |   |   |   |
| Foreign currency  translation                   |       | —                                |       | (265                                 | )          | — |   | 3,796 |   |
| Risk management  activities                     |       | (467                                  | )          | 3,666                                |       | 301 |   | 3,142 |   |
| Marketable  securities                          |       | 277                                   |       | —                               |       | (93 | ) | — |   |
| Total other  comprehensive income               |       | (190                                  | )          | 3,401                                |       | 208 |   | 6,938 |   |
|                                            |       |                                  |       |                                 |       |   |   |   |   |
| Comprehensive  income (loss)                    |       | $                                     | 379        |                                 | $          | (3,577 | ) | $ | (1,637 | ) | $ | 8,897 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

3

----

 

**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**

**(UNAUDITED)**

**(inthousands)**

 
| ** **                                                                                | ** ** | **Nine Months Ended September 30,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                | ** ** | **2004**                            | ** ** | **2003** | ** ** |
| **Cash  flows from operating activities:**                                                |       |                                |       |   |   |
| Net income  (loss)                                                                        |       | $                                   | (1,845     | ) | $ | 1,959 |   |
| Adjustments to  reconcile net income (loss) to net cash provided by operating activities: |       |                                |       |   |   |
| Cumulative  effect of change in accounting                                                |       | —                              |       | 29 |   |
| Depreciation,  depletion and amortization                                                 |       | 12,018                              |       | 18,814 |   |
| Amortization of  deferred financing costs included in interest expense                    |       | 3,836                               |       | 1,270 |   |
| Amortization of  intangible asset                                                         |       | 1,366                               |       | — |   |
| Loss from sale  of property, plant and equipment                                          |       | 145                                 |       | — |   |
| Non-cash  compensation expense                                                            |       | 732                                 |       | 554 |   |
| Equity in  investee losses                                                                |       | 50                                  |       | — |   |
| Non-controlling  interest in net income of consolidated subsidiary                        |       | 4,452                               |       | 3,342 |   |
| Derivative  ineffectiveness and non-cash mark-to-market adjustment                        |       | 732                                 |       | (2,207 | ) |
| Reclassification  of Enron hedges to purchased gas costs                                  |       | —                              |       | (153 | ) |
| Deferred income  taxes                                                                    |       | 1,732                               |       | (4,846 | ) |
| Gain on sale of  San Juan Basin properties                                                |       | —                              |       | (23,035 | ) |
| Cost of exiting  hedges                                                                   |       | —                              |       | (3,440 | ) |
| Other                                                                                     |       | (51                                 | )          | 427 |   |
| Changes in  operating assets and liabilities:                                             |       |                                |       |   |   |
| (Increase)  decrease in receivables                                                       |       | (13,122                             | )          | 15,046 |   |
| Increase in  inventories                                                                  |       | (7,635                              | )          | (2,540 | ) |
| Increase in  prepaid                                                                      |       | (7,233                              | )          | (3,941 | ) |
| Increase in  other current assets                                                         |       | (3,142                              | )          | — |   |
| Increase in  accounts payable and accrued liabilities                                     |       | 25,424                              |       | 309 |   |
| (Decrease)  increase in other long-term liabilities                                       |       | (2                                  | )          | 1,565 |   |
| Net cash flow  provided by operating activities                                           |       | 17,457                              |       | 3,153 |   |
|                                                                                      |       |                                |       |   |   |
| **Cash  flows from investing activities:**                                                |       |                                |       |   |   |
| Increase in  restricted cash                                                              |       | (550                                | )          | — |   |
| Increase in  marketable securities                                                        |       | (11,776                             | )          | — |   |
| East Texas  System acquisition                                                            |       | (240,606                            | )          | — |   |
| Hobbs Lateral acquisition                                                                 |       | (2,275                              | )          | — |   |
| 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                                                                     |       | (13,798                             | )          | (24,968 | ) |
| Proceeds from  sales of terminals                                                         |       | —                              |       | 2,438 |   |
| Proceeds from  sale of assets                                                             |       | 206                                 |       | — |   |
| Increase in  other contracts                                                              |       | (3,250                              | )          | — |   |
| Proceeds from  sale of assets to related parties                                          |       | 10                                  |       | 212 |   |
| Net cash used in  investing activities                                                    |       | (272,039                            | )          | (17,771 | ) |
|                                                                                           |            |                                     |            |  |  |  |  |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

4

----

 
| ** **                                                                                                                                             | ** ** | **Nine Months Ended September 30,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                                                                             | ** ** | **2004**                            | ** ** | **2003** | ** ** |
|                                                                                                                                                   |       |                                |       |   |   |
| **Cash  flows from financing activities:**                                                                                                             |       |                                |       |   |   |
| Proceeds from  long-term debt                                                                                                                          |       | 215,600                             |       | 86,835 |   |
| Repayment of  long-term debt                                                                                                                           |       | (144,300                            | )          | (75,130 | ) |
| Debt issuance  costs                                                                                                                                   |       | (7,193                              | )          | (811 | ) |
| Proceeds from  public offerings of MarkWest Energy Partners’ common units, net                                                                    |       | 140,014                             |       | — |   |
| Proceeds from  private placement of MarkWest Energy Partners’ common units, net                                                                   |       | 44,139                              |       | 9,764 |   |
| Distributions to  MarkWest Energy Partners’ unitholders                                                                                           |       | (9,603                              | )          | (5,173 | ) |
| Acquisitions and  dispositions of MarkWest Energy GP general partnership interests and MarkWest  Energy Partners subordinated units to related parties |       | (157                                | )          | 17 |   |
| Exercise of  stock options                                                                                                                             |       | 1,413                               |       | 333 |   |
| Net issuance  (buyback) of treasury shares                                                                                                             |       | 71                                  |       | (158 | ) |
| Payment of  dividends                                                                                                                                  |       | (5,288                              | )          | — |   |
| Net cash  provided by financing activities                                                                                                             |       | 234,696                             |       | 15,677 |   |
| Effect of  exchange rate on changes in cash                                                                                                            |       | —                              |       | 111 |   |
| Net increase  (decrease) in cash and cash equivalents                                                                                                  |       | (19,886                             | )          | 1,170 |   |
| Cash and cash  equivalents at beginning of period                                                                                                      |       | 42,144                              |       | 6,410 |   |
| Cash and cash  equivalents at end of period                                                                                                            |       | $                                   | 22,258     |   | $ | 7,580 |   |
| ** **                                                                                                                                             | ** ** | ** **                          | ** ** | ** ** | ** ** |
| **Supplemental  cash flow information:**                                                                                                               | ** ** | ** **                          | ** ** | ** ** | ** ** |
| Cash paid for  interest                                                                                                                                |       | $                                   | 4,607      |   | $ | 1,201 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

5

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**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATED STATEMENT OF CHANGES INSTOCKHOLDERS’ EQUITY**

**(UNAUDITED)**

**(inthousands)**

 
| ** **                      | ** ** | **Shares of  Common  Stock** | ** ** | **Shares of  Treasury  Stock** | ** ** | **Common  Stock** | ** ** | **Additional  Paid-In  Capital** | ** ** | **Accumulated  Earnings  (Deficit)** | ** ** | **Accumulated  Other  Comprehensive  Income  (Loss)** | ** ** | **Treasury Stock** | ** ** | **Total Stockholders’ Equity** | ** ** |
|---------------------------------|------------|------------------------------|------------|--------------------------------|------------|-------------------|------------|----------------------------------|------------|--------------------------------------|------------|-------------------------------------------------------|------------|--------------------|------------|-------------------------------------|------------|
|                            |       |                         |       |                           |       |              |       |                             |       |                                 |       |                                                  |       |               |       |                                |       |
| Balance,  December 31, 2003     |       | 9,638                        |       | (76                            | )          | $                 | 96         |                             | $          | 50,715                               |       | $                                                     | 3,676      |               | $          | (1,793                              | )          | $ | (510 | ) | $ | 52,184 |   |
|                            |       |                         |       |                           |       |              |       |                             |       |                                 |       |                                                  |       |               |       |                                |       |
| Stock option  exercises         |       | 197                          |       | —                         |       | 2                 |       | 1,694                            |       | —                               |       | —                                                |       | —             |       | 1,696                               |       |
|                            |       |                         |       |                           |       |              |       |                             |       |                                 |       |                                                  |       |               |       |                                |       |
| Dividends                       |       | —                       |       | —                         |       | —            |       | —                           |       | (5,288                               | )          | —                                                |       | —             |       | (5,288                              | )          |
|                            |       |                         |       |                           |       |              |       |                             |       |                                 |       |                                                  |       |               |       |                                |       |
| Net loss                        |       | —                       |       | —                         |       | —            |       | —                           |       | (1,845                               | )          | —                                                |       | —             |       | (1,845                              | )          |
|                            |       |                         |       |                           |       |              |       |                             |       |                                 |       |                                                  |       |               |       |                                |       |
| Other  comprehensive income     |       | —                       |       | —                         |       | —            |       | —                           |       | —                               |       | 208                                                   |       | —             |       | 208                                 |       |
|                            |       |                         |       |                           |       |              |       |                             |       |                                 |       |                                                  |       |               |       |                                |       |
| Net treasury  stock reissuances |       | —                       |       | 10                             |       | —            |       | —                           |       | —                               |       | —                                                |       | 71                 |       | 71                                  |       |
|                            |       |                         |       |                           |       |              |       |                             |       |                                 |       |                                                  |       |               |       |                                |       |
| Balance, September  30, 2004    |       | 9,835                        |       | (66                            | )          | $                 | 98         |                             | $          | 52,409                               |       | $                                                     | (3,457     | )                  | $          | (1,585                              | )          | $ | (439 | ) | $ | 47,026 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

6

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**MARKWEST HYDROCARBON, INC.**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**(UNAUDITED)**

** **

**1.****              General**

 

MarkWest Hydrocarbon,Inc. (“we”, “us” or “our”) markets natural gas and natural gas liquids itself,and also manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” orthe “Partnership”), through our majority ownership in the general partner ofthe Partnership.  MarkWest EnergyPartners is a publicly traded master limited partnership engaged in thegathering, processing and transmission of natural gas; the transportation, fractionationand storage of natural gas liquids (NGLs); and the gathering and transportationof crude oil.   Our employees areresponsible for conducting the Partnership’s business and operating its assets,pursuant to a Services Agreement.

 

Our assets consistprimarily of partnership interests in MarkWest Energy Partners.  As of September 30, 2004, our partnershipinterests consisted of 2,469,496 subordinated units, representing a 23% limitedpartner interest in the Partnership and a 90% membership (ownership) interestin MarkWest Energy GP, L.L.C., the general partner of the Partnership, whichowns a 2% general partner interest and all of the incentive distribution rightsin the Partnership.

 

The consolidatedfinancial statements include the accounts of MarkWest Hydrocarbon, Inc. and oursubsidiaries, including MarkWest Energy Partners. Through consolidation, wehave eliminated all significant intercompany accounts and transactions. We havereclassified certain prior period amounts to conform to the current year’spresentation.

 

We haveprepared the unaudited financial statements presented herein in accordance withthe instructions to Form 10-Q.  Thestatements do not include all the information and note disclosures required bygenerally accepted accounting principles for complete financialstatements.  Please read the interimconsolidated financial statements in conjunction with the ConsolidatedFinancial Statements and attached notes for the year ended December 31, 2003,included in our Annual Report on Form 10-K, as filed with the Securities andExchange Commission.  In the opinion ofmanagement, we have made all necessary adjustments for a fair statement of theresults for the unaudited interim periods. All said adjustments are of a recurring nature.

 

We base theeffective corporate tax rate for interim periods on the estimated annualeffective corporate tax rate.

 

**2.****              Stock and UnitCompensation**

 

As permitted underStatement of Financial Accounting Standards (“SFAS”) No. 123, *Accounting for Stock-Based Compensation,*and SFAS No. 148, *Accounting for Stock-Based Compensation – Transition and Disclosure*, we have elected to continue tomeasure compensation costs for stock-based and unit-based employee compensationplans as prescribed by Accounting Principles Board Opinion (“APB”) No. 25, *Accounting for Stock Issued to Employees.*We have two fixedcompensation plans and, through our consolidated subsidiary, MarkWest EnergyPartners, we have a variable plan. We account for these plans using fixed andvariable accounting as appropriate under APB 25.

 

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

 

7

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| ** **                                                                                                                                   | ** ** | **Three Months Ended September 30,**      | ** ** | **Nine Months Ended September 30,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                                                                   | ** ** | **2004**                                  | ** ** | **2003**                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                                                                   | ** ** | **(in thousands, except per share data)** | ** ** |
| Net income  (loss), as reported                                                                                                              |       | $                                         | 569        |                                | $          | (6,978 | ) | $ | (1,845 | ) | $ | 1,959 |   |
| Add:  compensation expense included in reported net income (loss)                                                                            |       | 431                                       |       | 72                                  |       | 775 |   | 343 |   |
| Deduct: total  stock-based employee compensation expense determined under fair value based  method for all awards, net of related tax effect |       | (459                                      | )          | (180                                | )          | (858 | ) | (636 | ) |
| Pro forma net  income (loss)                                                                                                                 |       | $                                         | 541        |                                | $          | (7,086 | ) | $ | (1,928 | ) | $ | 1,666 |   |
|                                                                                                                                         |       |                                      |       |                                |       |   |   |   |   |
| Net income  (loss) per share:                                                                                                                |       |                                      |       |                                |       |   |   |   |   |
| Basic:                                                                                                                                       |       |                                      |       |                                |       |   |   |   |   |
| As reported                                                                                                                                  |       | $                                         | 0.06       |                                | $          | (0.74 | ) | $ | (0.19 | ) | $ | 0.21 |   |
| Pro forma                                                                                                                                    |       | $                                         | 0.06       |                                | $          | (0.76 | ) | $ | (0.20 | ) | $ | 0.18 |   |
| Diluted:                                                                                                                                     |       |                                      |       |                                |       |   |   |   |   |
| As reported                                                                                                                                  |       | $                                         | 0.06       |                                | $          | (0.74 | ) | $ | (0.19 | ) | $ | 0.21 |   |
| Pro forma                                                                                                                                    |       | $                                         | 0.06       |                                | $          | (0.76 | ) | $ | (0.20 | ) | $ | 0.18 |   |

 

Compensationexpense for the variable plan, including restricted unit grants, is measuredusing the market price of MarkWest Energy Partners’ common units on the datethe number of units in the grant becomes determinable and is amortized intoearnings over the period of service.  Ourstock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock optionsunless the options were granted at an exercise price lower than market on thegrant date.

 

**3.****              MarkWestEnergy Partners’ Common Unit Offerings**

 

DuringJanuary 2004, the Partnership completed an offering of 1,100,444 common unitsat $39.90 per unit for gross proceeds of $43.9 million.  In addition, of the 172,200 common unitsavailable to underwriters to cover over-allotments, 72,500 were sold for grossproceeds of $2.9 million. To maintain its 2% interest, the general partner ofthe Partnership contributed $1.0 million, of which $0.1 million was fromdirectors and officers of the general partner. Gross proceeds from parties other than MarkWest Hydrocarbon, Inc. of$46.9 million less associated offering costs of $3.8 million resulted in netproceeds from the secondary public offering of $43.1 million.  As approximately $1.0 million of the offeringcosts had been incurred during fiscal 2003, net cash generated from theoffering during 2004 was approximately $44.1 million.

 

DuringJuly 2004, the Partnership sold 1,304,438 common units at $34.50 per unit forgross proceeds of $45.0 million in a private placement to certain accreditedinvestors.  Transaction costs were $1.0million and the capital contribution from the general partner to maintain its2% general partner interest was $0.9 million. Net proceeds were used to partially finance the American Central EasternTexas Gas Co, Limited Partnership (“American Central East Texas”) Carthagegathering system and gas processing assets (See Note 5).

 

On September 21, 2004, the Partnership completed asecondary public offering of 2,323,609 of its common units at $43.41 per unitfor gross proceeds of $100.9 million and 157,395 common units sold by certainselling unitholders.  Of the 2,323,609common units sold, 323,609 common units were sold by the Partnership pursuantto the underwriter’s over-allotment option. MarkWest Energy Partners did notreceive any proceeds from the common units sold by the sellingunitholders.  The total net proceeds fromthe offering, after deducting transaction costs of $5.2 million and includingthe general partner’s 2% capital contribution of $2.1 million, were $97.8million and were used to repay a portion of the outstanding indebtedness underthe amended and restated credit facility.

 

8

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**4.****              MarketableSecurities**

 

Marketablesecurities are classified as available-for-sale and stated at market based onthe closing price of the securities at the balance sheet date.  Accordingly, unrealized gains or temporarylosses are reflected in other comprehensive income (loss), net of applicableincome taxes.  For losses that are otherthan temporary, the cost basis of the securities is written down to fair valueand the amount of the write-down is reflected in the statement ofoperations.  We utilize aweighted-average cost basis to compute realized gains and losses.  Realized gains and losses, and dividend andinterest income, are reflected in earnings.

 

During the first quarterof 2004, we funded a $5.0 million brokerage account to invest primarily inequity securities of other Master Limited Partnerships.  As of September 30, 2004, the fair value ofthe invested securities was approximately $5.4 million.  Of this amount $0.3 million was recorded as anet unrealized gain through an adjustment to other comprehensive income.

 

In addition to equitysecurities, we invested approximately $9.3 million in Fannie Mae, Ginnie Maeand Freddie Mac callable debt securities, with interest rates ranging from2.75% to 4.25%, and maturities ranging from May 2006 through November2009.  These debt securities arereflected in marketable securities.

 

Debt and equity securitieswere acquired to provide both capital gains and investment income, and areclassified as available-for-sale.  Thefollowing is a summary of gross unrealized gains and losses:

 
| ** **               | ** ** | **September****30, 2004** | ** ** |
|--------------------------|------------|---------------------------|------------|
| ** **               | ** ** | **(in thousands)**        | ** ** |
| Gross unrealized  gains  |       | $                         | 357        |   |
| Gross unrealized  losses |       | (54                       | )          |
|                     |       |                      |       |
| Net unrealized  gain     |       | $                         | 303        |   |

 

**5.****              MarkWest Energy Partners’ Acquisitions**

 

*EastTexas System Acquisition*

 

On July 30,2004, MarkWest Energy Partners completed the acquisition (the “East TexasSystem acquisition”) of American Central East Texas’ Carthage gathering systemand gas processing assets located in East Texas for approximately $240.6million.  Through the consolidation ofthe Partnership, we have included the East Texas System acquisition results ofoperations from July 30, 2004.

 

Assets acquired consistof processing plants, gathering systems, a processing facility currently underconstruction and an NGL pipeline to be constructed in 2005.

 

There were a number offactors that led to the acquisition of the East Texas System assets.  We believe that the East Texas Systemcomplements the Partnership’s existing businesses in several ways and providesthe Partnership with a number of growth opportunities through its attractivecharacteristics.  The majority of theEast Texas System’s cash flow is generated from its natural gas gatheringoperations, which are tied to contracts generally ranging in length from fiveto 10 years.  The East Texas Systemfeatures natural gas pipelines with centralized receipt points connected tocommon suction or common discharge gathering pipelines.  This configuration provides a high degree ofreliability and enables MarkWest Energy Partners to offer both low- andhigh-pressure service to their customers. The system benefits from low fuel and operating costs because of itsdesign, age and large, efficient, standardized compressor stations.  We believe that the Carthage Field served bythe East Texas System is an attractive operating area for the Partnershipbecause it has long-lived reserves and significant development potential.  The East Texas System also provides MarkWestEnergy Partners with a platform on which to vertically integrate its businessthrough construction of a natural gas processing facility and NGLpipeline.  The Partnership has alreadyobtained contractual commitments that will fill the plant’s capacity.

 

9

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In conjunction with theclosing of the acquisition, the Partnership completed an offering of 1,304,438of its common units, at $34.50 per unit, which netted MarkWest Energy Partnersapproximately $44.9 million after transaction costs and the general partnercontribution.  In addition, thePartnership amended and restated its credit facility, increasing the maximumlending limit from $140.0 million to $315.0 million.  The credit facility includes a $265.0 millionrevolving facility and a $50.0 million term loan facility.  MarkWest Energy Partners used the proceedsfrom the offering and borrowings under the amended and restated credit facilityto partially finance the East Texas System acquisition. All of the Partnership’sassets are pledged to the credit facility lenders to secure the repayment ofthe outstanding borrowings under the credit facility. The term loan portion ofthe amended and restated credit facility matures in December 2004, and therevolving portion matures in May 2005. In October 2004, the Partnership amended and restated its creditfacility, decreasing the maximum lending limit from $315.0 million to $200.0million and increasing the term of the facility to five years (See Note 9).

 

The purchase price was comprised of$240.6 million, and was allocated as follows (in thousands):

 
| Acquisition  costs:               |   |    |    |
|-----------------------------------|--------|---------|---------|
| Cash  consideration               |   | $       | 240,211 |   |
| Direct  acquisition costs         |   | 396     |    |
| Total                             |   | $       | 240,607 |   |
|                              |   |    |    |
| Allocation of  acquisition costs: |   |    |    |
| Property, plant  and equipment    |   | $       | 76,634  |   |
| Customer  contracts               |   | 163,973 |    |
| Total                             |   | $       | 240,607 |   |
|                                   |        |         |         |  |  |  |

 

Ofthe total purchase price, approximately $164.0 million was allocated toamortizable intangible assets (See Note 8).

 

Allocation of thepurchase price is preliminary because certain items such as the determinationof the fair value of certain assets as of the acquisition date and thesettlement of certain purchase price adjustments included in the purchase andsale agreement have not been finalized.

 

*Hobbs Lateral Acquisition*

 

On April 1, 2004, the Partnership acquired the Hobbs Lateral pipeline forapproximately $2.3 million.  The HobbsLateral consists of a four-mile pipeline, with a capacity of 160 million cubicfeet of natural gas per day, connecting the Northern Natural Gas interstatepipeline to Southwestern Public Service’s Cunningham and Maddox powergenerating stations in Hobbs, New Mexico. The Hobbs Lateral is a New Mexico intrastate pipeline regulated by theFederal Energy Regulatory Commission. The pro forma results of operations of the Hobbs Lateral acquisitionhave not been presented as they are not significant.

 

*MichiganCrude Pipeline*

 

OnDecember 18, 2003, MarkWest Energy Partners completed the acquisition (the “MichiganCrude Pipeline acquisition”) of Shell Pipeline Company, LP’s and EquilonEnterprises, LLC’s, doing business as Shell Oil Products US (“Shell”), MichiganCrude Gathering Pipeline (the “System”), for approximately $21.3 million. TheSystem’s results of operations have been included in the Partnership’sconsolidated financial statements since December 18, 2003. The $21.3 millionpurchase price was financed through borrowings under the Partnership’s line ofcredit.

 

TheSystem extends from production facilities near Manistee, Michigan to a storagefacility near Lewiston, Michigan.  Thetrunk line consists of approximately 150 miles of pipe.  Crude oil is gathered into the System from 57injection points, including 52 central production facilities and five truckunloading facilities.  The System alsoincludes truck-unloading stations at Manistee, Seeley Road and Junction, andthe Samaria Truck Unloading Station located in Monroe County, Michigan, nearToledo, Ohio.

 

10

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TheSystem is a common carrier Michigan intrastate pipeline and gathers light crudeoil from wells.  The oil is transportedfor a fee to the Lewiston, Michigan station where it is batch injected into theEnbridge Lakehead Pipeline.

 

Thepurchase price was comprised of $21.3 million paid in cash to Shell plus directacquisition costs and was allocated as follows (in thousands):

 
| Acquisition  costs:               |   |   |   |
|-----------------------------------|--------|--------|--------|
| Cash  consideration               |   | $      | 21,155 |   |
| Direct  acquisition costs         |   | 128    |   |
| Total                             |   | $      | 21,283 |   |
|                              |   |   |   |
| Allocation of  acquisition costs: |   |   |   |
| Property, plant  and equipment    |   | $      | 21,283 |   |

 

###### *WesternOklahoma Acquisition*

###### * *

On December 1, 2003, MarkWest Energy Partners completedthe acquisition of certain assets of American Central Western Oklahoma GasCompany, L.L.C. (“AWOC”) for approximately $38.0 million. Results of operations for the acquired assets have been included in thePartnership’s consolidated financial statements since that date.

 

The assets acquired include the Foss Lake gatheringsystem located in the western Oklahoma counties of Roger Mills and Custer.  The gathering system is comprised ofapproximately 167 miles of pipeline, connected to approximately 270 wells, and11,000 horsepower of compression facilities. The assets also include the Arapaho gas processing plant that wasinstalled during 2000.

 

The purchase price of approximately $38.0 million wasfinanced through borrowings under the Partnership line of credit, which wasamended at the closing of the acquisition to increase availability under thecredit facility from $75.0 million to $140.0 million.

 

The purchase price was comprised of$38.0 million paid in cash to AWOC, and was allocated as follows (inthousands):

 
| Acquisition  costs:               |   |   |   |
|-----------------------------------|--------|--------|--------|
| Cash consideration                |   | $      | 37,850 |   |
| Direct  acquisition costs         |   | 101    |   |
| Total                             |   | $      | 37,951 |   |
|                              |   |   |   |
| Allocation of  acquisition costs: |   |   |   |
| Property, plant  and equipment    |   | $      | 37,951 |   |

###### * *

###### *LubbockPipeline Acquisition*

###### * *

OnSeptember 2, 2003, MarkWest Energy Partners completed the acquisition (the “LubbockPipeline acquisition”) of a 68-mile intrastate gas transmission pipeline systemnear Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2million.  The transaction was financedthrough borrowings under the Partnership’s then-existing credit facility.  The acquisition was accounted for as apurchase business combination.  The proforma results of operations of the Lubbock Pipeline acquisition have not beenpresented, as they are not significant.

 

11

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###### *PinnacleAcquisition*

###### * *

On March 28, 2003, MarkWest EnergyPartners completed the acquisition (the “Pinnacle acquisition”) of PinnacleNatural Gas Company, Pinnacle Pipeline Company, PNG TransmissionCompany, Inc., PNG Utility Company and Bright Star Gathering, Inc.(collectively, “Pinnacle” or the “Sellers”). Pinnacle’s results of operations have been included in the Partnership’sconsolidated financial statements since that date.

 

The Pinnacle acquisition was accomplishedthrough a merger under Texas law of the Sellers and four newly formed whollyowned subsidiaries of the Partnership as buyers. In the merger, most of theassets and liabilities of the Sellers were allocated to the Partnershipentities, and all entities survived the merger. The assets acquired from theSellers, primarily located in the State of Texas, with the balance located inNew Mexico, Louisiana, Mississippi and Kansas, were comprised of three lateralnatural gas pipelines and twenty gathering systems.

 

The purchase price wasallocated as follows (in thousands):

 
| Acquisition  costs:                           |   |   |   |
|-----------------------------------------------|--------|--------|--------|
| Long-term debt  incurred                      |   | $      | 39,471 |   |
| Direct  acquisition costs                     |   | 450    |   |
| Current  liabilities assumed                  |   | 8,945  |   |
| Total                                         |   | $      | 48,866 |   |
|                                          |   |   |   |
| Allocation of  acquisition costs:             |   |   |   |
| Current assets                                |   | $      | 10,643 |   |
| Fixed assets  (including long-term contracts) |   | 38,223 |   |
| Total                                         |   | $      | 48,866 |   |

 

*Pro Forma Results of Operations (Unaudited)*

 

Thefollowing table reflects the unaudited pro forma consolidated results ofoperations for the comparable period presented, as though the Pinnacleacquisition, the Western Oklahoma acquisition, the Michigan Crude Pipeline andthe East Texas System acquisition each had occurred as of the beginning of theperiod presented.  The unaudited proforma results have been prepared for comparative purposes only and may not beindicative of future results.  The pro forma results of operations of theHobbs Lateral acquisition and the Lubbock Pipeline acquisition have not beenpresented, as they are not significant (in thousands, except per unit data).

 
| ** **                                                  | ** ** | **Three Months  Ended  September 30,  2004** | ** ** | **Three Months  Ended  September 30,  2003** | ** ** | **Nine Months  Ended  September 30,  2004** | ** ** | **Nine Months  Ended  September 30,  2003** | ** ** |
|-------------------------------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|---------------------------------------------|------------|---------------------------------------------|------------|
| Revenue                                                     |       | $                                            | 126,511    |                                         | $          | 66,949                                      |       | $                                           | 325,100    |   | $ | 223,042 |   |
| Income (loss) from  continuing operations                   |       | $                                            | 936        |                                         | $          | (8,003                                      | )          | $                                           | (1,290     | ) | $ | (26,948 | ) |
| Basic income  (loss) from continuing operations per share   |       | $                                            | 0.10       |                                         | $          | (0.85                                       | )          | $                                           | (0.13      | ) | $ | (2.88 | ) |
| Diluted income  (loss) from continuing operations per share |       | $                                            | 0.10       |                                         | $          | (0.85                                       | )          | $                                           | (0.13      | ) | $ | (2.88 | ) |

 

12

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##### **6.**              Property,Plant and Equipment

##### ** **

The following providescomposition of our property, plant and equipment at:

 
| ** **                                                              | ** ** | **September****30, 2004** | ** ** | **December 31, 2003** | ** ** |
|-------------------------------------------------------------------------|------------|---------------------------|------------|-----------------------|------------|
| ** **                                                              | ** ** | **(in thousands)**        | ** ** |
| Property, plant  and equipment:                                         |       |                      |       |                  |       |
| Gas gathering  facilities                                               |       | $                         | 147,004    |                  | $          | 73,424 |   |
| Gas processing  plants                                                  |       | 56,277                    |       | 55,888                |       |
| Fractionation  and storage facilities                                   |       | 22,496                    |       | 22,160                |       |
| Natural gas  pipelines                                                  |       | 38,842                    |       | 38,790                |       |
| Crude oil  pipeline                                                     |       | 18,522                    |       | 18,352                |       |
| NGL transportation  facilities                                          |       | 4,391                     |       | 4,415                 |       |
| Marketing assets                                                        |       | 1,606                     |       | 1,987                 |       |
| Oil and gas  properties and equipment, full cost method                 |       | 2,509                     |       | 2,380                 |       |
| Land, buildings  and other equipment                                    |       | 11,257                    |       | 12,499                |       |
| Construction  in-progress                                               |       | 21,240                    |       | 2,362                 |       |
|                                                                    |       | 324,144                   |       | 232,257               |       |
| Less: Accumulated  depreciation, depletion, amortization and impairment |       | (55,629                   | )          | (44,134               | )          |
| Total property,  plant and equipment, net                               |       | $                         | 268,515    |                  | $          | 188,123 |   |

 

*Cobb Processing Plant*

 

During2003, we entered into an agreement with the Partnership for the construction ofa new Cobb processing plant.  Initially,we expected the construction costs of the new plant and the costs todecommission and dismantle the old plant to be approximately $2.1 million, $1.7million to be funded by us and $0.4 million to be funded by thePartnership.  In the third quarter of2004, this number was revised and we now expect the costs to be $3.6 million toconstruct and $0.4 million to decommission and dismantle.  The Partnership will fund the $1.9 millionincrease in expected costs.  Constructionis expected to be completed by the end of 2004. As of September 30, 2004, we had contributed $1.3 million, resulting in$0.4 million to be contributed during the fourth quarter of fiscal 2004.

 

**7.****              Adoption of SFAS No. 143**

 

On January 1, 2003, we adopted SFAS No. 143, *Accounting for Asset Retirement Obligations.*  SFAS No. 143 requires entities to record thefair value of a liability for an asset retirement obligation in the period inwhich it is incurred and a corresponding increase in the carrying amount of therelated long-lived asset.  Subsequently,the asset retirement cost should be allocated to expense using a systematic andrational method.  During the firstquarter of 2003, we recorded a net-of-tax cumulative effect of change inaccounting principle charge of $29,000 ($63,000 before tax), and an assetretirement obligation of $3.4 million (a net increase to long-term liabilitiesof $2.5 million).  We also increased netproperties $2.4 million in accordance with the provisions of SFAS No. 143.  There was no impact on our cash flows as aresult of adopting SFAS No. 143.  Theasset retirement obligation, which is included in our consolidated balancesheet in other long-term liabilities, was $0.5 million and $3.8 million atSeptember 30, 2004 and 2003, respectively.

 

**8.****              Intangible Assets**

 

On July 30,2004, the Partnership completed the acquisition of American Central East Texas’Carthage gathering system and gas processing assets located in East Texas forapproximately $240.6 million.  Of thetotal purchase price, $164.0 million was allocated to amortizable intangibleassets (i.e., customer contracts) basedon the net present value of the projected cash flows. The key variablesthat determined the valuation of the customer contracts was the assumption ofrenewals, economic incentives to retain customers, historical volumes, currentand

 

13

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future capacity of the gatheringsystem and pricing volatility.  ThePartnership is amortizing the fair value of these customer contracts on astraight-line basis over an estimated economic life of 20 years.  The estimated economic life was determined byassessing the life of the assets to which the contracts relate, likelihood ofrenewals, competitive factors, regulatory or legal provisions, and maintenanceand renewal costs.

 

We entered into a series ofagreements with a gas producer in September, under which we process natural gasfor the producer under modified keep-whole contracts.  Other intangible assets include $3.3 million inconsideration given to the producer in connection with these non-separablecontracts that is being amortized over the term of the contracts, October 1,2004 through February 9, 2015.

 

The Partnership reviews long-livedassets for potential impairment whenever there is an indication that thecarrying amount may not be recoverable from future estimated cash flows.  Through September 30, 2004, the Partnership’smanagement believes that there have been no indications of impairment of thePartnership’s intangible assets.

 

The Partnership’spurchased intangible assets associated with the East Texas System acquisitionand other non-acquisition contract costs at September 30, 2004, are composed of(in thousands):

 
| ** **                                       | ** ** | **Gross** | ** ** | **2004  Accumulated  Amortization** | ** ** | **Net** | ** ** |
|--------------------------------------------------|------------|-----------|------------|-------------------------------------|------------|---------|------------|
| Customer  contracts (20 years)                   |       | $         | 163,973    |                                | $          | 1,366   |       | $ | 162,607 |   |
| Other (October  1, 2004 – February 9, 2015) |       | 3,250     |       | —                              |       | 3,250   |       |
| Total intangible  assets                         |       | $         | 167,223    |                                | $          | 1,366   |       | $ | 165,857 |   |

 

Amortizationexpense related to customer contracts was $1.4 million for the nine monthsended September 30, 2004.

 

Estimated futureamortization expense related to intangible assets at September 30, 2004 is asfollows (in thousands):

 
| Year ending  December 31: |   |    |   |
|---------------------------|--------|---------|--------|
| 2004                      |   | $       | 2,122  |   |
| 2005                      |   | 8,487   |   |
| 2006                      |   | 8,487   |   |
| 2007                      |   | 8,487   |   |
| 2008                      |   | 8,487   |   |
| 2009                      |   | 8,487   |   |
| Thereafter                |   | 121,300 |   |
|                           |        |         |        |  |

 

**9.****              Debt**

 

In July 2004 and August 2004, the Partnershipamended and restated its credit facility, increasing its maximum lending limitfrom $140.0 million to $315.0 million. The credit facility includes a $265.0 million revolving facility and a$50.0 million term loan facility. MarkWest Energy Partners used the proceeds from the offering andborrowings under its amended and restated credit facility to finance the EastTexas System acquisition. All of the Partnership’s assets are pledged to thecredit facility lenders to secure the repayment of the outstanding borrowingsunder the credit facility. The term loan portion of the amended and restatedcredit facility matures in December 2004, and the revolving portion matures inMay 2005.  Under the term loan, to theextent that a portion or all of the term loan is repaid, then those amounts maynot be reborrowed.  In addition, thereare certain restrictions on the reborrowing amounts paid under the revolverloan.  At September 30, 2004, $197.5million was outstanding, and $46.5 million was available under the Partnershipcredit facility.

 

The interestrate on the credit facility is determined using a variable interest rate basedon one of two indices that include either (i) LIBOR plus 3.5% to LIBOR plus4.5% or (ii) Base Rate (“BR”) (as defined for any day, a fluctuating rate perannum equal to the higher of (a) the Federal Funds Rate plus 1⁄2 of 1% and (b)the rate of interest in effect for such day as publicly announced from time totime by the Administrative Agent of the debt as its “prime rate”) plus 2.5% toBR plus 3.5%, depending on our maintenance of certain financial leverageratios.  The Partnership is also requiredto pay a commitment fee equal to the applicable rate (as defined in the creditagreement) times the actual daily amount by which the aggregate revolvercommitments exceed the sum of (i) the outstanding

 

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amount of revolver loans plus(ii) the outstanding amount of letters of credit obligations.  The commitment fee is due and payablequarterly in arrears on the last business day of each March, June, Septemberand December.  For the nine months endedSeptember 30, 2004, the weighted average interest rate was 5.4%.

 

*Subsequentevent*

 

In October2004, the Partnership amended and restated its credit facility, decreasing themaximum lending limit from $315.0 million to $200.0 million and increasing theterm of the facility to five years.  Thecredit facility includes a revolving facility of $200.0 million with thepotential to increase the maximum lending limit to $300.0 million.  The credit facility is guaranteed by thePartnership and all of its present and future subsidiaries and iscollateralized by substantially all of its existing and future assets and thoseof its subsidiaries, including stock and other equity interests.  The borrowing under the Partnership’s creditfacility will bear interest at a variable interest rate based on one of twoindices that include either (i) LIBOR plus an applicable margin, which is fixedat a rate of 2.75% for the first two quarters following the closing of thecredit facility or (ii) Base Rate (as defined for any day, a fluctuating rateper annum equal to the higher of (a) the Federal Funds Rate plus 1⁄2 of 1% and(b) the rate of interest in effect for such day as publicly announced from timeto time by the Administrative Agent of the debt as its “prime rate”) plus anapplicable margin, which shall be fixed at a rate of 2.00% for the first twoquarters following the closing of the credit facility.  After that period, the applicable margin willbe adjusted quarterly based on its ratio of funded debt to EBITDA (as definedin the credit agreement).   Consequently,as of September 30, 2004, we have classified the debt balance as non-current.

 

In connectionwith the credit facility, the Partnership is subject to a number ofrestrictions on its business, including restrictions on its ability to grantliens on assets, merge, consolidate or sell assets, incur indebtedness (otherthan subordinate indebtedness), make acquisitions, engage in other businesses,enter into capital or operating leases, engage in transactions with affiliates,make distributions on equity interests and other usual and customarycovenants.  In addition, the Partnershipis subject to certain financial maintenance covenants, including its ratios oftotal debt to EBITDA, total senior secured debt to EBITDA, EBITDA to interestand a minimum net worth requirement. Failure to comply with the provisions of any of these covenants couldresult in acceleration of the Partnership’s debt and other financialobligations.

 

In October2004, the Partnership issued $225.0 million of senior notes at a fixed rate of6.875% and with a maturity date of November 1, 2014.  Subject to compliance with certain covenants,the Partnership may issue additional notes from time to time under theindenture.   Interest on the notes accrueat the rate of 6.875% per year and are payable semi-annually in arrears on May1 and November 1, commencing on May 1, 2005. The Partnership may redeem some or all of the notes at any time on orafter November 1, 2009 at certain redemption prices together with accrued andunpaid interest to the date of redemption, and the Partnership may redeem allof the notes at any time prior to November 1, 2009 at a make-whole redemptionprice.  In addition, prior to November 1,2007, MarkWest Energy Partners may redeem up to 35% of the aggregate principalamount of the notes with the proceeds of certain equity offerings at a certainredemption price.  If the Partnershipsells certain assets and does not reinvest the proceeds or repay seniorindebtedness, or if it experiences specific kinds of changes in control, itmust offer to repurchase notes at a specified price.  Each of MarkWest Energy Partner’s existingsubsidiaries, other than MarkWest Energy Finance Corporation, has guaranteedthe notes initially and so long as such subsidiary guarantees any of thePartnership’s other debt.  Not all of thePartnership’s future subsidiaries will have to become guarantors.  The notes are senior unsecured obligationswith equal in right of payment with all of the existing and future senior debt.  These notes are senior in right of payment toall of the Partnership’s future subordinated debt but effectively junior inright of payment to its secured debt to the extent of the assets securing thedebt, including its obligations in respect to its bank credit facility.  The proceeds from these notes were used topay down the outstanding debt under the Partnership’s credit facility.

 

On October 25, 2004, we entered into a $25.0 million seniorcredit facility with a term of one year. The $25.0 million revolving facility has a variable interest rate basedon the base rate, which is equal to the higher of a) the Federal Funds Rateplus 1⁄2 of 1%, and b) the rate of interest in effect for such day as publiclyannounced from time to time by the Administrative Agent as its prime rate, plusthe applicable rate, which is based on a utilization percentage.  The amount available to be drawn under thecredit facility is based upon the amount of our eligible

 

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accounts receivable andinventory balance.  In addition, we arerequired to pay a commitment fee equal to the applicable rate times the actualdaily amount by which the aggregate commitment exceeds the sum of (i) the outstandingamount of loans plus (ii) the outstanding amount of our letter of creditobligations.  Substantially all of ourassets and those of our subsidiaries (other than excluded MarkWest EnergyPartners entities) are pledged to the lender to secure the repayment of theoutstanding borrowings under the credit facility.   The proceeds from this borrowing will beused to finance inventory and accounts receivable, issue letters of credit andpay fees, costs and expenses related to this agreement.  As of October 31, 2004, we had no outstandingborrowings.

 

**10.****       Recovery of Receivable**

 

During the fourth quarter of 2001, Enron Corporationand its subsidiaries (“Enron”) filed for bankruptcy protection.  In response to this filing, we terminated allderivative contracts where Enron was the counterparty.  As a result, in 2001 we wrote off $1.1million of risk management assets related to our cash flow hedges offset by$0.1 million of risk management liabilities related to our fair valuehedges.  In the third quarter of 2004, wesold our claim to these assets for $0.8 million.  As a result, we recorded $0.8 million asother income in the third quarter of 2004.

 

**11.****       Segment Reporting**

 

Our operations areclassified into two reportable segments:

 

(1)          ManagingMarkWest Energy Partners—we manage the business operations of MarkWest EnergyPartners, a publicly traded master limited partnership engaged in thegathering, processing and transmission of natural gas; the transportation,fractionation and storage of natural gas liquids; and the gathering andtransportation of crude oil.

(2)          Marketing—wesell our equity and third-party NGLs, purchase third-party natural gas and sellour equity and third-party natural gas.

 

During 2003, wediscontinued our exploration and production business segment. Our continuingoperations are conducted solely in the United States.

 

The table belowpresents information about operating income (loss) for the reported segmentsfor the three and nine months ended September 30, 2004 and 2003. Segmentoperating income (loss) includes total revenues less purchased product costs,facility expenses and depreciation and amortization. Items excluded fromsegment operating income (loss) are reflected in the reconciliation of totalsegment operating income (loss) to income (loss) from continuing operationsbefore taxes.

 
| ** **                                  | ** ** | **Marketing**      | ** ** | **MarkWest  Energy  Partners** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------|------------|--------------------|------------|--------------------------------|------------|--------------------------|------------|-----------|------------|
| ** **                                  | ** ** | **(in thousands)** | ** ** |
| **Three  Months Ended September 30, 2004:** |       |               |       |                           |       |                     |       |      |       |
| Revenues from  external customers           |       | $                  | 61,105     |                           | $          | 61,833                   |       | $         | —     |   | $ | 122,938 |   |
| Intersegment  revenues                      |       | $                  | 121        |                           | $          | 15,250                   |       | $         | (15,371    | ) | $ | — |   |
| Segment  operating income                   |       | $                  | 2,158      |                           | $          | 11,396                   |       | $         | —     |   | $ | 13,554 |   |
| Total segment  assets                       |       | $                  | 94,626     |                           | $          | 478,574                  |       | $         | (19,427    | ) | $ | 553,773 |   |
|                                        |       |               |       |                           |       |                     |       |      |       |
| **Three  Months Ended September 30, 2003:** |       |               |       |                           |       |                     |       |      |       |
| Revenues from external  customers           |       | $                  | 29,340     |                           | $          | 18,888                   |       | $         | —     |   | $ | 48,228 |   |
| Intersegment  revenues                      |       | $                  | 313        |                           | $          | 12,524                   |       | $         | (12,837    | ) | $ | — |   |
| Segment  operating income (loss)            |       | $                  | (9,197     | )                              | $          | 5,480                    |       | $         | —     |   | $ | (3,717 | ) |
| Total segment  assets                       |       | $                  | 159,630    |                           | $          | 142,290                  |       | $         | (14,176    | ) | $ | 287,744 |   |

 

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| ** **                                 | ** ** | **Marketing**      | ** ** | **MarkWest  Energy  Partners** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|--------------------------------------------|------------|--------------------|------------|--------------------------------|------------|--------------------------|------------|-----------|------------|
| ** **                                 | ** ** | **(in thousands)** | ** ** |
| **Nine  Months Ended September 30, 2004:** |       |               |       |                           |       |                     |       |      |       |
| Revenues from  external customers          |       | $                  | 142,445    |                           | $          | 161,977                  |       | $         | —     |   | $ | 304,422 |   |
| Intersegment  revenues                     |       | $                  | 459        |                           | $          | 43,350                   |       | $         | (43,809    | ) | $ | — |   |
| Segment  operating income (loss)           |       | $                  | (313       | )                              | $          | 25,488                   |       | $         | —     |   | $ | 25,175 |   |
| Total segment  assets                      |       | $                  | 94,626     |                           | $          | 478,574                  |       | $         | (19,427    | ) | $ | 553,773 |   |
|                                       |       |               |       |                           |       |                     |       |      |       |
| **Nine  Months Ended September 30, 2003:** |       |               |       |                           |       |                     |       |      |       |
| Revenues from  external customers          |       | $                  | 104,026    |                           | $          | 42,741                   |       | $         | —     |   | $ | 146,767 |   |
| Intersegment  revenues                     |       | $                  | 758        |                           | $          | 36,000                   |       | $         | (36,758    | ) | $ | — |   |
| Segment  operating income (loss)           |       | $                  | (21,173    | )                              | $          | 13,285                   |       | $         | —     |   | $ | (7,888 | ) |
| Total segment  assets                      |       | $                  | 159,630    |                           | $          | 142,290                  |       | $         | (14,176    | ) | $ | 287,744 |   |
|                                            |            |                    |            |                                |            |                          |            |           |            |  |  |  |  |  |  |

 

A reconciliation of totalsegment operating income (loss) to loss from continuing operations before taxesis as follows:

 
| ** **                                                         | ** ** | **Three Months Ended September 30,** | ** ** | **Nine Months Ended September 30,** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|
| ** **                                                         | ** ** | **2004**                             | ** ** | **2003**                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                         | ** ** | **(in thousands)**                   | ** ** |
| Segment  operating income (loss)                                   |       | $                                    | 13,554     |                                | $          | (3,717 | ) | $ | 25,175 |   | $ | (7,888 | ) |
| Selling, general  and administrative expenses                      |       | (5,966                               | )          | (3,549                              | )          | (14,712 | ) | (9,462 | ) |
| Loss on sale of  terminals                                         |       | —                               |       | (55                                 | )          | — |   | (55 | ) |
| Interest  expense, net                                             |       | (7,002                               | )          | (1,115                              | )          | (9,452 | ) | (4,176 | ) |
| Gain on sale to  related party                                     |       | —                               |       | —                              |       | — |   | 188 |   |
| Non-controlling  interest in net income of consolidated subsidiary |       | (210                                 | )          | (1,607                              | )          | (4,452 | ) | (3,342 | ) |
| Other income                                                       |       | 553                                  |       | 31                                  |       | 585 |   | 15 |   |
| Income (loss)  from continuing operations before income taxes      |       | $                                    | 929        |                                | $          | (10,012 | ) | $ | (2,856 | ) | $ | (24,720 | ) |

 

**12.****      ****Related Party Transactions**

 

William P.Nicoletti, who serves as a member of MarkWest Energy Partners general partner’sboard of directors, the general partner of the Partnership, is a member of theboard of directors of Star Gas LLC, the general partner of Star Gas Partners,L.P., a retail propane and heating oil master limited partnership.  Star Gas Propane, a subsidiary of Star GasPartners, L.P., is a significant customer of ours, and generated revenue ofapproximately $4.3 million and $16.3 million for the three and nine monthsended September 30, 2004, respectively, and $2.0 million and $14.1 million forthe three and nine months ended September 30, 2003, respectively.  On September 30, 2004, our outstandingreceivable balance with Star Gas Partners, L.P. was $0.9 million.

 

Star GasPartners, L.P.’s heating oil distribution subsidiary, Petro, announced onOctober 18 that it has been unable to pass along record heating-oil prices toits customers and that its 2004 net income will be substantially below netincome for 2003. Through our discussions with Star Gas Propane, we expect toreceive full payment for the outstanding receivable balance because Star Gas Propanehas its own financing that is not connected to Petro.  As a result, we have not reserved for theoutstanding receivable balance.  However,we will assess doing business with Star Gas Propane and the allowance, if any,for doubtful accounts.  Should there be achange in circumstance, we will adjust the reserve accordingly.  In addition, we believe that we will be ableto sustain the revenue generated from this customer in 2004 and the foreseeablefuture.

 

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**13.****       Commitments andContingencies**

 

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

 

Asummary of our total contractual cash obligations as of September 30, 2004, isas follows (in thousands):

 
| **Type of  Obligation** | ** ** | **Total  Obligation** | ** ** | **Due in  2004-2005** | ** ** | **Due in  2006-2007** | ** ** | **Thereafter** | ** ** |
|-------------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|----------------|------------|
| Operating Leases        |       | $                     | 14,050     |                  | $          | 5,600                 |       | $              | 4,448      |   | $ | 4,002 |   |
| Debt                    |       | 197,500               |       | —                |       | —                |       | 197,500        |       |
| Total                   |       | $                     | 211,550    |                  | $          | 5,600                 |       | $              | 4,448      |   | $ | 201,502 |   |

 

**14.****       Recent Accounting Pronouncements**

 

On March 31, 2004, the EmergingIssues Task Force issued EITF No. 03-6 which clarifies the computation ofearnings per share in SFAS No. 128, for companies that have issued securitiesother than common stock that entitle the holder to participate in the company’sdeclared dividends and earnings.  The consensus states that securitiesshould be included in basic earnings per share calculations when the holder isentitled to receive dividends rather than if the holder is entitled to receiveearnings or value upon redemption of the securities or liquidation ofassets.  The effective date of EITF No. 03-6 is the first fiscal periodbeginning after March 31, 2004, and requires restatement of prior periodinformation.  Implementation of the consensushad no effect on the financial results and resulted in no change in earningsper share for the three month and nine month periods ending September 30, 2004,and 2003.

 

**15.****      ****SubsequentEvent**

 

On November 8, 2004, aleak occurred in a natural gas liquids (NGLs) line owned by Equitable Supply,and leased and operated by MarkWest Energy Appalachia, LLC, a subsidiary ofMarkWest Energy Partners.  The 4-inchpipeline transports NGLs from the Partnership’s Maytown gas processing plant toits Siloam fractionator.  A subsequentignition and fire from the leaked vapors resulted in property damage to fivehomes and injuries to some of the residents. The exact cause of the leak and resulting fire is unknown and is beinginvestigated by MarkWest Energy Partners and the U.S. Department ofTransportation Office of Pipeline Safety.  Until repairs are completed and service is resumed on the line, NGLsfrom the Maytown plant will be trucked directly to the Siloam fractionator,resulting in a minor impact to the Partnership’s operations.

 

While investigation intothe incident continues, at this time the Partnership believes that it hasadequate insurance coverage for property damage and personal injury liability,if any, resulting from the incident.

##### ** **

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

##### ** **

##### **Management Overview of the Three and Nine MonthsEnded September 30, 2004**

##### ** **

We reported net incomefor the three months ended September 30, 2004 of $0.6 million, or $0.06 perdiluted share, compared to a net loss of $7.0 million, or $0.74 per dilutedshare, for the third quarter of 2003. For the nine months ended September 30, 2004, we reported a net loss of$1.8 million, or $0.19 per diluted share, compared to net income of $2.0million, or $0.21 per diluted share, for the nine months ended September 30,2003.

 

We reported net incomefrom continuing operations of $0.6 million, or $0.06 per diluted share, for thethree months ended September 30, 2004, compared to a net loss from continuingoperations of $6.3 million, or $0.67 per diluted share, for the third quarterof 2003.  For the nine months endedSeptember 30, 2004, we reported a net loss from continuing operations of $1.8million, or $0.19 per diluted share, compared to a net loss from continuingoperations of $15.7 million, or $1.67 per diluted share, for the correspondingnine months of 2003.

 

The improved results forthe third quarter of 2004 as compared to the corresponding quarter of 2003 wasattributed to the impact of better NGL product margins, the non-recurrence ofapproximately $3.9 million of crude oil hedging losses and higher NGL productsales volumes.  Other matters benefitingthird quarter results included an approximate $0.8 million in other income fromthe sale of the rights to a former Enron receivable that had been previouslywritten-off.

 

The improved net incomefrom continuing operations for the first nine months of 2004 as compared to thecorresponding period of 2003 was also attributed to the factors impacting thethird quarter comparisons.  Approximately$10.9 million of the change was attributable to a reduction in our crude oilhedging losses.  The remainder of thechange was primarily due to better NGL product margins and due to acquisitionsmade by MarkWest Energy Partners, late in 2003 and in the third quarter of2004.

 

Finally, in September2004, we entered into several new and amended agreements with one of thelargest Appalachia producers, which allow us to significantly reduce ourexposure to commodity price risk for approximately 25% of our keep-whole gasvolumes.

 

On October 28, 2004, ourboard of directors declared a stock dividend of one share of our common stockfor each ten shares of common stock held by our common stockholders.  The stock dividend is to be paid on November19, 2004 to stockholders of record as of the close of business on November 9,2004.

 

On the same date, ourboard of directors declared a cash dividend of $0.05 per share of its commonstock held by our common stockholders. This represented a $0.025 per share increase over the previous quarter’sdividend.  The indicated annual rate is$0.20 per share.  Our board has declaredthat the dividend is to be paid on December 6, 2004, to the stockholders ofrecord as of the close of business on November 24, 2004.

 

## **Our Business**

## ** **

We were foundedin 1988 as a partnership and later incorporated in Delaware.  We completed our initial public offering in1996.

 

We are anenergy company primarily focused on increasing shareholder value by growingMarkWest Energy Partners, our consolidated subsidiary, and a publicly tradedmaster limited partnership engaged in the gathering, processing andtransmission of natural gas; the transportation, fractionation and storage ofnatural gas liquids; and the gathering and transportation of crude oil. We alsomarket natural gas and natural gas liquids through our processing contracts andwholesale marketing business. We discontinued our exploration and productionactivities during 2003.

 

Our assets consistprimarily of partnership interests in MarkWest Energy Partners.  As of September 30, 2004, our partnershipinterests consisted of the following:

 

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•                  2,469,496subordinated units, representing a 23% limited partner interest in thePartnership; and

•                  A90% ownership interest in MarkWest Energy GP, L.L.C., the general partner ofthe Partnership, which owns a 2% general partner interest and all of theincentive distribution rights in the Partnership.

 

To better understand our business and theresults of operations discussed below, it is important to have an understandingof three factors:

 

•                  The nature of our relationship withMarkWest Energy Partners;

•                  The nature of the contracts fromwhich we derive our revenues and from which MarkWest Energy Partners derivesits revenues; and

•                  The comparability within our resultsof operations across periods because of MarkWest Energy Partners’ significantand recent acquisition activity.

 

***Our Relationship with MarkWest EnergyPartners***

 

We spun off the majority of our then-existingnatural gas gathering and processing and NGL transportation, fractionation andstorage assets into MarkWest Energy Partners in May 2002, just before thePartnership completed its initial public offering. At the time of its formationand initial public offering, we entered into four contracts with MarkWestEnergy Partners whereby MarkWest Energy Partners provides midstream services tous in Appalachia in exchange for fees. These fees are accounted for as facilityexpenses.  Additionally, MarkWest EnergyPartners receives 100% of all fee and percent-of-proceeds consideration for thefirst 10 MMcf/d that it gathers and processes in Michigan. We retain a 70% netprofits interest in the gathering and processing income earned on quarterlypipeline throughput in excess of 10 MMcf/d.

 

In accordance with generally acceptedaccounting principles, MarkWest Energy Partners’ financial results are includedin our consolidated financial statements. All intercompany accounts and transactions are eliminated duringconsolidation. You should read Note 11 to our Consolidated Financial Statementsappearing earlier in this Form 10-Q for further information regarding our twobusiness segments: managing the business operations of MarkWest Energy Partnersand marketing.

 

As a result ofour contracts with MarkWest Energy Partners mentioned above, we are thePartnership’s largest customer, accounting for 20% and 21% of its revenues forthe three and nine months ended September 30, 2004, respectively, and 24% and31% of its gross margin for the three and nine months ended September 30, 2003,respectively. We expect to account for less of MarkWest Energy Partners’business in the future as MarkWest Energy Partners expands its existingoperations, continues to acquire assets and increases its customer and businessdiversification.

 

Also, at the time of theinitial public offering, we entered into an Omnibus Agreement with MarkWestEnergy Partners and related parties that governs potential competition andindemnification obligations among the parties.

 

Through our majorityownership in the Partnership’s general partner, we manage the businessoperations of MarkWest Energy Partners. Our employees are responsible forconducting the Partnership’s business and operating its assets pursuant to aServices Agreement, which was formalized effective January 1, 2004. We receive$5,000 annually from MarkWest Energy Partners for services provided under theServices Agreement. We also are reimbursed for any reasonable costs incurred inthe operation of the Partnership.

 

***Our Contracts***

 

Excludingthe revenues and gross margin derived by MarkWest Energy Partners, the majorityof our revenues and gross margin are generated from providing processing services,and from our marketing of NGLs and, to a lesser extent, natural gas.  As compensation for providing processingservices to Appalachian producers (we have outsourced these services toMarkWest Energy Partners as discussed above), we earn a fee and receive titleto the NGLs produced.  In return, we arerequired to replace, in dry natural gas, the Btu value of the NGLs extracted.

 

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This Btu replacement obligation is referred to in the industry as a “keep-whole”arrangement.  In keep-whole arrangements,our principal cost is the replacement of the Btus extracted from the gas streamin the form of NGLs or consumed as fuel during processing with dry gas of anequivalent Btu content.  The spreadbetween the NGL product sales price and the purchase price of natural gas withan equivalent Btu content is called the “frac spread.”  In the event natural gas and the cost ofprocessing becomes more expensive, on a Btu equivalent basis, when compared toNGL products, the cost of keeping the producer “whole”, in conjunction with ouroperating costs, results in operating losses.

 

Our keep-whole contractsexpose us to commodity price risk, both on the sales side (of NGLs) and on thepurchase side (of natural gas), which may increase the volatility of ourmarketing results and cash flows. However, in September, we entered intoseveral new and amended agreements with one of the largest Appalachiaproducers, which allow us to significantly reduce our exposure to commodity pricerisk for approximately 25% of our keep-whole gas volumes. We also attempt tomitigate our commodity price risk through our hedging program. Under a hedgingstrategy implemented approximately two years ago that was based on ourthen-existing natural gas production and historical pricing data through thatpoint in time, we incurred significant hedging losses. For the nine monthsended September 30, 2004 and 2003, we lost approximately $2.7 million and $13.6million, respectively, as a result of that hedging strategy.  The last transactions associated with thishedging strategy settled in April 2004. You should read Item 3, “Quantitativeand Qualitative Disclosures About Market Risk” for further details about ourcommodity price risk management program, which is incorporated herein byreference.

 

### ***MarkWest Energy Partners’ Contracts***

### ** **

ThePartnership generates the majority of its revenues and gross margin (defined asrevenues less purchased product costs) from natural gas gathering, processingand transmission, NGL transportation, fractionation and storage, and crude oilgathering and transportation.  While allof these services constitute midstream energy operations, the Partnershipprovides its services pursuant to five different types of contracts.

 

•                  *Fee-basedcontracts.*  Under fee-basedcontracts, the Partnership receives a fee or fees for one or more of thefollowing services: gathering, processing, and transmission of natural gas,transportation, fractionation and storage of NGLs, and gathering and transportationof crude oil. The revenue the Partnership earns from these contracts isdirectly related to the volume of natural gas, NGLs or crude oil that flowsthrough its systems and facilities and is not directly dependent on commodityprices. In certain cases, the contracts provide for minimum annualpayments.  To the extent a sustaineddecline in commodity prices results in a decline in volumes, however, thePartnership’s revenues from these contracts would be reduced.

 

•                  *Percent-of-proceedscontracts.*  Underpercent-of-proceeds contracts, the Partnership generally gathers and processesnatural gas on behalf of producers, sells the resulting residue gas and NGLs atmarket prices and remits to producers an agreed upon percentage of the proceedsbased on an index price. In other cases, instead of remitting cash payments tothe producer, MarkWest Energy Partners delivers an agreed upon percentage ofthe residue gas and NGLs to the producer and sells the volumes it keeps tothird parties at market prices. Under these types of contracts, the Partnership’srevenues and gross margins increase as natural gas prices and NGL pricesincrease, and its revenues and gross margins decrease as natural gas prices andNGL prices decrease.

 

•                  *Percent-of-indexcontracts.*  Under percent-of-indexcontracts, the Partnership generally purchases natural gas at either (1) apercentage discount to a specified index price, (2) a specified indexprice less a fixed amount or (3) a percentage discount to a specifiedindex price less an additional fixed amount. MarkWest Energy Partners thengathers and delivers the natural gas to pipelines where it resells the naturalgas at the index price.  With respect to(1) and (3) above, the gross margins the Partnership realizes under thearrangements described above decrease in periods wherein natural gas prices arefalling because these gross margins are based on a percentage of the indexprice. Conversely, our gross margins increase during periods of rising naturalgas prices.

 

•                  *Keep-wholecontracts.*  Under keep-wholecontracts, the Partnership gathers natural gas from the producer, processes thenatural gas and sells the resulting NGLs to third parties at market prices.Because the extraction

 

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of the NGLs from the natural gas during processingreduces the Btu content of the natural gas, the Partnership must eitherpurchase natural gas at market prices for return to producers or make cashpayment to the producers equal to the value of this natural gas. Accordingly,under these arrangements, the Partnership’s revenues and gross margins increaseas the price of NGLs increase relative to the price of natural gas, and itsrevenues and gross margins decrease as the price of natural gas increasesrelative to the price of NGLs.

 

•                  *EastTexas System gathering arrangements.* The Partnership gathers volumes on the East Texas System under contractswith fee arrangements that are unique to that system.  These contracts typically contain one or moreof the following revenue components:

 

•                  *Fixedgathering and compression fees.* Typically, gathering and compression fees are comprised of a fixed feeportion in which producers pay a fixed rate per unit to transport their naturalgas through the gathering system.  Underthe majority of these arrangements, fees are adjusted annually based on theConsumer Price Index.

 

•                  *Settlementmargin. *Typically, the termsof the Partnership’s East Texas System gathering arrangements specify that itis allowed to retain a fixed percentage of the volume gathered to cover thecompression fuel charges and deemed line losses.  To the extent the East Texas System isoperated more efficiently than provided for by contracted allowances, MarkWestEnergy Partners is entitled to retain the difference for its own account.

 

•                  *Condensatesales.*  During the gatheringprocess, thermodynamic forces contribute to changes in operating conditions ofthe natural gas flowing through the pipeline infrastructure.  As a result, hydrocarbon dew points arereached, causing condensation of hydrocarbons in the high-pressurepipelines.  The East Texas System sells100% of the condensate collected in the system at a monthly crude-oil basedprice.

 

Inmany cases, the Partnership provides services under contracts that contain acombination of more than one of the arrangements described above.  The terms of the contracts vary based on gasquality conditions, the competitive environment at the time the contracts aresigned and customer requirements.  Thecontract mix and, accordingly, the Partnership’s exposure to natural gas andNGL prices, may change as a result of changes in producer preferences, thePartnership’s expansion in regions where some types of contracts are morecommon and other market factors.  Anychange in MarkWest Energy Partners’ contract mix may impact the financialresults.

 

AtSeptember 30, 2004, the Partnership’s primary exposure to keep-whole contractswas limited to its Arapaho (OK) processing plant and its East Texas (“Carthage”)processing contract with a third party. At the Arapaho (OK) plant inlet, the Btu content of the natural gasmeets the downstream pipeline specifications; however, MarkWest Energy Partnershas the option of extracting NGLs when the processing margin environment isfavorable.  In addition, approximatelyhalf, as measured in volumes, of the related gas gathering contracts includeadditional fees to cover plant operating costs, fuel costs and shrinkage costsin a low processing margin environment. Because of the Partnership’s ability to operate the plant in severalrecovery modes, including turning it off, coupled with the additional feesprovided for in the gas gathering contracts, the Partnership’s overallkeep-whole contract exposure is limited to a portion of the operating costs ofthe plant.

 

Inregards to the exposure to keep-whole contracts in Carthage, the Partnershiphas a third party processing agreement to offer percent of liquids (“POL”)processing services to area customers and to process gas for its ownaccount.  Of the total system inlet,approximately 26% of the volume is processed under POL terms and 16% isprocessed as keep-whole gas.  Theremaining 58% is subject to gathering services. However, the exposure is limited by the Partnership’s ability to rejector recover ethane to help manage the keep-whole processing volumes.

 

***Recent MarkWest Energy Partners AcquisitionActivity***

 

In reading the discussion of our historical results ofoperations, you should be aware of MarkWest Energy Partners’ recent significantacquisitions, which impact the comparability of our results of operations forthe periods discussed.

 

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From its initial public offering through September 30,2004, the Partnership has completed six acquisitions for an aggregate purchaseprice of approximately $354.3 million. These six acquisitions include:

 

•                                          the Pinnacle acquisition, which closed on March 28,2003, for consideration of $39.9 million;

 

•                                          the Lubbock pipeline acquisition (also known asthe Power-Tex Lateral pipeline), which closed on September 2, 2003, for consideration of $12.2 million;

 

•                                          the western Oklahoma acquisition, which closed on December 1,2003, for consideration of $38.0 million;

 

•                                          the Michigan Crude Pipeline acquisition, whichclosed on December 18, 2003, for consideration of $21.3 million;

 

•                                          the Hobbs Lateral acquisition, which closed onApril 1, 2004, for consideration of $2.3 million; and

 

•                                          the East Texas System acquisition, which closed onJuly 30, 2004, for consideration of $240.6 million.

 

Our historical results of operations for the nine months ended September30, 2003, save for six months of activity from the Pinnacle acquisition and onemonth for the Lubbock pipeline acquisition, do not reflect the impact of theseacquisitions on our operations. However, our results of operations for thethree months ended September 30, 2004, do reflect the impact from the four 2003acquisitions, three months of operations for the Hobbs Lateral acquisition andtwo months of results from the East Texas System acquisition.  The results of operations for the nine monthsended September 30, 2004, reflect the impact from the four 2003 acquisitions,six months of operations for the Hobbs Lateral acquisition and two months ofresults from the East Texas acquisition.

 

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##### **Resultsof Operations**

 

***Operating Data***

 
| ** **                                 | ** ** | **Three Months Ended September 30,** | ** ** | **Nine Months Ended September 30,** | ** ** |
|--------------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|
| ** **                                 | ** ** | **2004**                             | ** ** | **2003**                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Marketing**                              |       |                                 |       |                                |       |   |   |   |   |
| NGL product sales (gallons)                |       | 42,900,000                           |       | 40,800,000                          |       | 130,100,000 |   | 125,700,000 |   |
| **Wholesale**(1)                           |       |                                 |       |                                |       |   |   |   |   |
| NGL product sales (gallons)                |       | 10,879,000                           |       | —                              |       | 15,816,000 |   | — |   |
| **MarkWest Energy Partners**               |       |                                 |       |                                |       |   |   |   |   |
| Appalachia:                                |       |                                 |       |                                |       |   |   |   |   |
| Natural gas processed for a fee (Mcf/d)(2) |       | 196,000                              |       | 204,000                             |       | 201,000 |   | 198,000 |   |
| NGLs fractionated for a fee (Gal/d)        |       | 489,000                              |       | 511,000                             |       | 474,000 |   | 449,000 |   |
| NGL product sales (gallons)                |       | 10,710,000                           |       | 10,771,000                          |       | 32,638,000 |   | 29,142,000 |   |
| Michigan:                                  |       |                                 |       |                                |       |   |   |   |   |
| Natural gas processed for a fee (Mcf/d)    |       | 12,300                               |       | 17,300                              |       | 12,800 |   | 15,900 |   |
| NGL product sales (gallons)                |       | 2,453,000                            |       | 3,982,000                           |       | 7,557,000 |   | 9,112,000 |   |
| Crude oil transported for a fee (Bbl/d)(3) |       | 15,100                               |       | —                              |       | 14,800 |   | — |   |
| Southwest:                                 |       |                                 |       |                                |       |   |   |   |   |
| Gathering systems throughput (Mcf/d):      |       |                                 |       |                                |       |   |   |   |   |
| East Texas System(4)                       |       | 246,600                              |       | —                              |       | 246,600 |   | — |   |
| Foss Lake (OK)(5)                          |       | 63,300                               |       | —                              |       | 60,700 |   | — |   |
| Appleby (6)                                |       | 24,500                               |       | 25,200                              |       | 23,300 |   | 24,300 |   |
| Other gathering systems (6)                |       | 15,500                               |       | 21,300                              |       | 17,700 |   | 21,100 |   |
| Lateral throughput volumes (Mcf/d)(7)      |       | 97,200                               |       | 43,600                              |       | 83,100 |   | 43,600 |   |
| NGL product sales (gallons):               |       |                                 |       |                                |       |   |   |   |   |
| Arapaho (OK)(8)                            |       | 12,174,000                           |       | —                              |       | 28,686,000 |   | — |   |
| East Texas System(4)                       |       | 12,268,000                           |       | —                              |       | 12,268,000 |   | — |   |

 

----

(1)  Wholesale NGL product sales started inFebruary 2004.

(2)  Includesthroughput from our Kenova, Cobb, and Boldman processing plants.

(3)  We acquired ourMichigan Crude Pipeline in December 2003.

(4)  We acquired ourEast Texas System in late July 2004.

(5)  We acquired ourFoss Lake (OK) gathering system in December 2003.

(6)  We acquired ourPinnacle gathering systems in late March 2003.

(7)  We acquired ourPower-Tex Lateral pipeline (a/k/a the Lubbock Pipeline) in September 2003 andour Hobbs lateral pipeline in April 2004. The Power-Tex and Hobbs Lateral pipelines are the only laterals we ownthat produce revenue on a per-unit-of-throughput basis.  We receive a flat fee from our other lateralpipelines and, consequently, the throughput data from these three lateralpipelines is excluded from this statistic.

(8)  We acquired ourArapaho (OK) processing plant in December 2003.

 

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***Three Months EndedSeptember 30, 2004 Compared to the Three Months Ended September 30, 2003***

 
| ** **                                  | ** ** | **Marketing**      | ** ** | **MarkWest  Energy  Partners** | ** ** | **Eliminating  Entries** | ** ** | **Total**  | ** ** |
|---------------------------------------------|------------|--------------------|------------|--------------------------------|------------|--------------------------|------------|------------|------------|
| ** **                                  | ** ** | **(in thousands)** | ** ** |
| **Three  Months Ended September 30, 2004:** | ** ** | ** **         | ** ** | ** **                     | ** ** | ** **               | ** ** | ** ** | ** ** |
| Revenues                                    |       | $                  | 61,226     |                           | $          | 77,083                   |       | $          | (15,371    | ) | $ | 122,938 |   |
|                                        |       |               |       |                           |       |                     |       |       |       |
| Purchased  product costs                    |       | 52,564             |       | 51,635                         |       | (9,071                   | )          | 95,128     |       |
| Facility  expenses                          |       | 6,201              |       | 8,380                          |       | (6,300                   | )          | 8,281      |       |
| Depreciation and  amortization              |       | 303                |       | 5,672                          |       | —                   |       | 5,975      |       |
| Total segment  operating expenses           |       | 59,068             |       | 65,687                         |       | (15,371                  | )          | 109,384    |       |
|                                        |       |               |       |                           |       |                     |       |       |       |
| Segment  operating income                   |       | $                  | 2,158      |                           | $          | 11,396                   |       | $          | —     |   | $ | 13,554 |   |
|                                        |       |               |       |                           |       |                     |       |       |       |
| **Three  Months Ended September 30, 2003:** |       |               |       |                           |       |                     |       |       |       |
| Revenues                                    |       | $                  | 29,653     |                           | $          | 31,412                   |       | $          | (12,837    | ) | $ | 48,228 |   |
|                                        |       |               |       |                           |       |                     |       |       |       |
| Purchased  product costs                    |       | 32,294             |       | 18,510                         |       | (6,283                   | )          | 44,521     |       |
| Facility  expenses                          |       | 6,362              |       | 5,396                          |       | (6,554                   | )          | 5,204      |       |
| Depreciation and  amortization              |       | 194                |       | 2,026                          |       | —                   |       | 2,220      |       |
| Total segment  operating expenses           |       | 38,850             |       | 25,932                         |       | (12,837                  | )          | 51,945     |       |
|                                        |       |               |       |                           |       |                     |       |       |       |
| Segment  operating income (loss)            |       | $                  | (9,197     | )                              | $          | 5,480                    |       | $          | —     |   | $ | (3,717 | ) |

 
| ** **                                                         | ** ** | **Three Months Ended September 30,** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                         | ** ** | **2004**                             | ** ** | **2003** | ** ** |
| ** **                                                         | ** ** | **(in thousands)**                   | ** ** |
| Segment  operating income (loss)                                   |       | $                                    | 13,554     |   | $ | (3,717 | ) |
| Selling, general  and administrative                               |       | (5,966                               | )          | (3,549 | ) |
| Loss on sale of  terminals                                         |       | —                               |       | (55 | ) |
| Interest  expense, net                                             |       | (7,002                               | )          | (1,115 | ) |
| Non-controlling  interest in net income of consolidated subsidiary |       | (210                                 | )          | (1,607 | ) |
| Other income                                                       |       | 553                                  |       | 31 |   |
|                                                               |       |                                 |       |   |   |
| Income (loss)  from continuing operations before income taxes      |       | $                                    | 929        |   | $ | (10,012 | ) |

 

*Marketing.*Our marketing segmentoperating income was $2.2 million for the three months ended September 30,2004, compared to a loss of $9.2 million for the three months ended September30, 2003, a change of $7.0 million. The increase is primarily due to higher NGL product sales prices andvolumes.  In addition, approximately $3.9million of the change was attributable to a reduction in our hedging losses.

 

*MarkWestEnergy Partners.*Segmentoperating income from MarkWest Energy Partners was $11.4 million for the threemonths ended September 30, 2004, compared to $5.5 million for the three monthsended September 30, 2003, an increase of $5.9 million, or 107%. The increase isprimarily attributable to the Partnership’s late 2003 and 2004 acquisitions,which contributed $6.6 million to operating income.  This was offset by an increase of $0.7million in depreciation expense primarily as a result of accelerating thedepreciation of our Michigan gathering pipeline and processing plant by reducingthe estimated useful lives of the related assets from twenty years to fifteenyears to more closely match expected lives of reserves behind our facilities.

 

*Selling,*g*eneral and administrative expenses.* Selling, general andadministrative expenses were $6.0 million for the three months ended September30, 2004, compared to $3.5 million for the three months ended September 30,2003, an increase of $2.5 million, or 71%. The increase is attributable to several factors, including additionaladministrative costs associated with the growth of MarkWest Energy Partners,through its 2003 and 2004 acquisitions,

 

25

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Sarbanes Oxley compliance expenses, bonus andprofit sharing (bonus was not accrued during the three months ended September30, 2003) and increases in franchise taxes and insurance.

 

*Interest expense, net.*  Interest expense, net was $7.0million for the three months ended September 30, 2004, compared to $1.1 millionfor the three months ended September 30, 2003, an increase of $5.9 million, or536%. The increase was principally attributable to amortization and write offof deferred financing costs from the amendment and restatement of our creditfacility in July 2004.  In addition,interest expense increased due to greater debt levels resulting from thefinancing of our late 2003 and 2004 acquisitions and an increase in our averageinterest rate.

 

*Loss**fromdiscontinued operations.*Lossfrom discontinued operations was $0 for the three months ended September 30,2004, compared to $0.7 million for the three months ended September 30, 2003, adecrease of $0.7 million. The decrease was a result of the sale ofsubstantially all of our U.S. exploration and production business near the endof the second quarter of 2003.

 

***Nine Months EndedSeptember 30, 2004 Compared to the Nine Months Ended September 30, 2003***

 
| ** **                                 | ** ** | **Marketing**      | ** ** | **MarkWest  Energy  Partners** | ** ** | **Eliminating  Entries** | ** ** | **Total**  | ** ** |
|--------------------------------------------|------------|--------------------|------------|--------------------------------|------------|--------------------------|------------|------------|------------|
| ** **                                 | ** ** | **(in thousands)** | ** ** |
| **Nine  Months Ended September 30, 2004:** | ** ** | ** **         | ** ** | ** **                     | ** ** | ** **               | ** ** | ** ** | ** ** |
| Revenues                                   |       | $                  | 142,904    |                           | $          | 205,327                  |       | $          | (43,809    | ) | $ | 304,422 |   |
|                                       |       |               |       |                           |       |                     |       |       |       |
| Purchased  product costs                   |       | 124,036            |       | 146,695                        |       | (25,016                  | )          | 245,715    |       |
| Facility  expenses                         |       | 18,139             |       | 20,801                         |       | (18,793                  | )          | 20,147     |       |
| Depreciation and  amortization             |       | 1,042              |       | 12,343                         |       | —                   |       | 13,385     |       |
| Total segment operating  expenses          |       | 143,217            |       | 179,839                        |       | (43,809                  | )          | 279,247    |       |
|                                       |       |               |       |                           |       |                     |       |       |       |
| Segment  operating income (loss)           |       | $                  | (313       | )                              | $          | 25,488                   |       | $          | —     |   | $ | 25,175 |   |
|                                       |       |               |       |                           |       |                     |       |       |       |
| **Nine  Months Ended September 30, 2003:** |       |               |       |                           |       |                     |       |       |       |
| Revenues                                   |       | $                  | 104,784    |                           | $          | 78,741                   |       | $          | (36,758    | ) | $ | 146,767 |   |
|                                       |       |               |       |                           |       |                     |       |       |       |
| Purchased  product costs                   |       | 108,089            |       | 45,325                         |       | (18,533                  | )          | 134,881    |       |
| Facility  expenses                         |       | 17,308             |       | 14,900                         |       | (18,225                  | )          | 13,983     |       |
| Depreciation and  amortization             |       | 560                |       | 5,231                          |       | —                   |       | 5,791      |       |
| Total segment  operating expenses          |       | 125,957            |       | 65,456                         |       | (36,758                  | )          | 154,655    |       |
|                                       |       |               |       |                           |       |                     |       |       |       |
| Segment  operating income (loss)           |       | $                  | (21,173    | )                              | $          | 13,285                   |       | $          | —     |   | $ | (7,888 | ) |

 
| ** **                                                         | ** ** | **Nine Months Ended September 30,** | ** ** |
|--------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                         | ** ** | **2004**                            | ** ** | **2003** | ** ** |
| ** **                                                         | ** ** | **(in thousands)**                  | ** ** |
| Segment  operating income (loss)                                   |       | $                                   | 25,175     |   | $ | (7,888 | ) |
| Selling, general  and administrative                               |       | (14,712                             | )          | (9,462 | ) |
| Loss on sale of  terminals                                         |       | —                              |       | (55 | ) |
| Interest  expense, net                                             |       | (9,452                              | )          | (4,176 | ) |
| Gain on sale to  related party                                     |       | —                              |       | 188 |   |
| Non-controlling  interest in net income of consolidated subsidiary |       | (4,452                              | )          | (3,342 | ) |
| Other income                                                       |       | 585                                 |       | 15 |   |
|                                                               |       |                                |       |   |   |
| Loss from  continuing operations before income taxes               |       | $                                   | (2,856     | ) | $ | (24,720 | ) |

 

26

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*Marketing.*Our marketing segmentoperating loss was $0.3 million for the nine months ended September 30, 2004,compared to a loss of $21.2 million for the nine months ended September 30,2003, a decrease of $20.9 million, or 99%. Approximately $10.9 million of thechange was attributable to a reduction in our hedging losses.  The remainder of the change is primarilyattributable to higher NGL productsales prices and volumes.

 

*MarkWestEnergy Partners.*Segmentoperating income from MarkWest Energy Partners was $25.5 million for the ninemonths ended September 30, 2004, compared to $13.3 million for the nine monthsended September 30, 2003, an increase of $12.2 million, or 92%. The increase isprimarily attributable to the Partnership’s late 2003 and 2004 acquisitions,which contributed $13.2 million to operating income. This was offset by anincrease in depreciation expense primarily as a result of accelerating thedepreciation of our Michigan gathering pipeline and processing plant byreducing the estimated useful lives of the related assets from twenty years tofifteen years to more closely match expected lives of reserves behind ourfacilities.

 

*Selling,*g*eneral and administrative expenses.* Selling, general andadministrative expenses were $14.7 million for the nine months ended September30, 2004, compared to $9.5 million for the nine months ended September 30,2003, an increase of $5.2 million, or 55%. The increase is attributable to several factors, including additionaladministrative costs associated with the growth of MarkWest Energy Partners,through its 2003 and 2004 acquisitions, Sarbanes Oxley compliance expenses,bonus and profit sharing (bonus was not accrued during the nine months endedSeptember 30, 2003) and increases in franchise taxes and insurance.

 

*Interest expense, net.*  Interest expense, net was $9.5million for the nine months ended September 30, 2004, compared to $4.2 millionfor the nine months ended September 30, 2003, an increase of $5.3 million, or126%. The increase was primarily attributable to amortization and write off ofdeferred financing costs from the amendment and restatement of our creditfacility in July 2004.  In additioninterest expense increased due to heightened debt levels resulting from thefinancing of our late 2003 and 2004 acquisitions and an increase in our averageinterest rate.

 

*Income**fromdiscontinued operations.*Incomefrom discontinued operations was $0 for the nine months ended September 30,2004, compared to $17.7 million, net of tax, for the nine months endedSeptember 30, 2003, a decrease of $17.7 million. The decrease was a result ofthe sale of substantially all of our U.S. exploration and production businessnear the end the second quarter of 2003.

 

**Liquidityand Capital Resources**

 

During 2003, wediscontinued our exploration and production activities and sold all of ourrelated Canadian oil and gas properties and substantially all of our U.S. oiland gas properties.  The sales netted us$106.7 million in cash.  The proceedswere primarily used to pay off and terminate our then existing credit facilityin its entirety in December 2003. We also had $33.4 million in unrestrictedcash on hand at December 31, 2003, exclusive of MarkWest Energy Partners’ $8.7million cash on hand. As a result, exclusive of MarkWest Energy Partners’ debt,we had no debt as of September 30, 2004 and December 31, 2003. In February2004, we disbursed approximately $4.8 million to pay a special one-timedividend of $0.50 per share to our common stockholders. In May 2004, wedisbursed approximately $0.2 million to pay the first quarterly dividend of$0.025 per common share to our common shareholders. On August 19, 2004, wedisbursed approximately $0.2 million to pay the second quarterly dividend of$0.025 per share to our common stockholders. On October 28, 2004, our board of directors declared a stock dividend ofone share of our common stock for each ten shares of common stock held by ourcommon stockholders.  The stock dividendis to be paid on November 19, 2004, to the stockholders of record as of theclose of business on November 9, 2004. On the same date, our board of directorsalso announced that it declared a quarterly cash dividend of$0.05 per share of our common stock. This represented a $0.025 per share increase over the previous quarter’sdividend.  The indicated annual rate is$0.20 per share.  Our Board has declaredthat the dividend is to be paid on December 6, 2004, to the stockholders ofrecord as of the close of business on November 24, 2004.

 

Going forward,we expect our primary sources of liquidity to be quarterly distributionsreceived from MarkWest Energy Partners and cash flows generated principallyfrom providing processing services and the associated marketing of natural gasand NGLs.

 

27

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We own 90% of the generalpartner of MarkWest Energy Partners.  Thegeneral partner of MarkWest Energy Partners owns a 2% general partner interestand all of the incentive distribution rights in MarkWest Energy Partners.  The incentive distribution rights entitle usto receive, through the general partner, an increasing percentage of cashdistributed by the Partnership upon attainment of target distribution levels.Specifically, incentive distribution rights entitle us to receive 13% of theincremental cash distributed in a quarter greater than $0.55 per unit and up toand including $0.625 per unit for that quarter; 23% of the incremental cashdistributed in a quarter greater than $0.625 per unit and up to and including$0.75 per unit for that quarter; and 48% of the incremental cash distributed ina quarter above $0.75 per unit for that quarter. For the nine months endedSeptember 30, 2004, we received $5.2 million in distributions for oursubordinated units, and the general partner received $0.9 million, including$0.7 million representing payments on incentive distribution rights. As thePartnership continues to grow and increase its quarterly distributions perlimited partner unit, we expect corresponding increases in our distributions.

 

Cash flowsgenerated from providing processing services and our marketing operations aresubject to volatility primarily in NGLs and natural gas prices.  Our cash flows are enhanced in periods whenthe prices received for NGLs exceed the prices paid for natural gas we purchaseto satisfy our “keep-whole” contractual arrangements in Appalachia, and arereduced in periods when the prices received for NGLs are low relative to theprice of natural gas we purchase to satisfy such contractual arrangements.Under “keep-whole” contracts, we retain and sell the NGLs produced in ourprocessing operations for third-party producers, and then reimburse or “keepwhole” the producers for the Btu content of the NGLs removed through there-delivery to the producers of an equivalent amount (on a Btu basis) of drynatural gas. Generally, the frac spread and, consequently, the operatingmargins, are favorable. Periodically, when natural gas becomes more expensive,on a Btu equivalent basis, compared to NGL products, the cost of keeping theproducer “whole”, in conjunction with our operating costs, can result inoperating losses. As noted previously, we entered into several new and amendedagreements in September with one of the largest Appalachia producers that allowus to significantly reduce our exposure to commodity price risk forapproximately 25% of our keep-whole gas volumes. We, however, cannot predictwith any certainty what the pricing environment will be in the future.

 

On October 25, 2004, weentered into a $25.0 million senior credit facility with a term of oneyear.  The $25.0 million revolving facilityhas a variable interest rate based on the base rate, which is equal to thehigher of a) the Federal Funds Rate plus 1⁄2 of 1%, and b) the rate of interestin effect for such day as publicly announced from time to time by theAdministrative Agent as its prime rate, plus the applicable rate, which isbased on a utilization percentage.  Theamount available to be drawn under the credit facility is based upon the amountof our eligible accounts receivable and inventory balance.  In addition, we are required to pay acommitment fee equal to the applicable rate times the actual daily amount bywhich the aggregate commitment exceeds the sum of (i) the outstanding amount ofloans plus (ii) the outstanding amount of our letter of credit obligations.  Substantially all of our assets and oursubsidiaries (other than excluded MarkWest Energy Partners entities) arepledged to the lender to secure the repayment of the outstanding borrowingsunder the credit facility.   The proceedsfrom this borrowing will be used to finance inventory and accounts receivable,issue letters of credit and pay fees, costs and expenses related to thisagreement.  As of October 31, 2004, wehad no outstanding borrowings.

 

We believe that cash onhand, cash received from quarterly distributions (including the incentivedistribution rights) from MarkWest Energy Partners, and cash generated from ourprocessing services and marketing operations will be sufficient to meet ourworking capital requirements and fund our required capital expenditures, ifany, for the foreseeable future. Most of our future capital expenditures arediscretionary and minimal in nature. During 2004, we have budgeted $1.0 million for our capital contributionto MarkWest Energy Partners for our share of the costs to replace the Cobbplant and an additional $0.1 million for other miscellaneous projects.  As of September 30, 2004 we had contributed$1.3 million for the Cobb plant, including amounts contributed in 2003,resulting in $0.4 million to be contributed during the fourth quarter of fiscal2004.  Cash generated from our processingservices and marketing operations will depend on our operating performance,which will be affected by prevailing commodity prices and other factors, some ofwhich are beyond our control.

 

In an effort to increase ourliquidity, we may renegotiate certain keep-whole contracts in order to reduceour commodity price risk.

 

28

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***MarkWestEnergy Partners***

 

*Partnership EquityOfferings*

 

DuringJanuary 2004, the Partnership completed an offering of 1,100,444 of its commonunits, at $39.90 per unit, which netted approximately $44.9 million aftertransaction costs and the general partner contribution.  The Partnership primarily used the proceedsto pay down its outstanding debt.

 

During July 2004,MarkWest Energy Partners completed a private placement of 1,304,438 of itscommon units, at $34.50 per unit, which netted approximately $44.9 millionafter transaction costs and the general partner contribution.  The Partnership used the proceeds from theoffering to finance the East Texas System acquisition.

 

OnSeptember 21, 2004, MarkWest Energy Partners completed a public offering of2,323,609 of its common units at $43.41 per unit for gross proceeds of $100.9million and 157,395 common units sold by certain selling unitholders.  Of the 2,323,609 common units sold, 323,609common units were sold pursuant to the underwriter’s over-allotmentoption.  The Partnership did not receiveany proceeds from the common units sold by the selling unitholders.  Total net proceeds from the offering, afterdeducting transaction costs of $5.2 million and including the general partner’s2% capital contribution of $2.1 million, were $97.8 million and were used torepay a portion of the outstanding indebtedness under the amended and restatedcredit facility.

 

*Partnership Debt*

 

ThePartnership’s $315.0 million credit facility, as amended and restated in August2004, is available to fund capital expenditures and certain permittedacquisitions and distributions to unitholders. Advances to fund distributionsto unitholders may not exceed $0.50 per outstanding unit in any12-consecutive-month period. To date there have been no advances under thecredit facility to fund distributions to unitholders.  Under the term loan, to the extent that a portion or all ofthe term loan is repaid, then those amounts may not be reborrowed.  In addition, there are certain restrictionson the reborrowing of amounts paid under the revolver loan.  At September 30, 2004, $197.5 millionwas outstanding, and $46.5 million was available for borrowing, under thePartnership’s credit facility.

 

In October2004, the Partnership’s credit facility was amended and restated, decreasingthe maximum lending limit from $315.0 million to $200.0 million and increasingthe term of the facility to five years. The credit facility includes a revolving facility of $200.0 million withthe potential to increase the maximum lending limit to $300.0 million.  The credit facility is guaranteed by thePartnership and all of its present and future subsidiaries and iscollateralized by substantially all of its existing and future assets and thoseof its subsidiaries, including stock and other equity interests.  The borrowing under the credit facility willbear interest at a variable interest rate based on one of two indices thatinclude either (i) LIBOR plus an applicable margin, which is fixed at a rate of2.75% for the first two quarters following the closing of the credit facilityor (ii) Base Rate (as defined for any day, a fluctuating rate per annum equalto the higher of (a) the Federal Funds Rate plus 1/2 of1% and (b) the rate of interest in effect for such day as publicly announcedfrom time to time by the Administrative Agent of the debt as its “prime rate”)plus an applicable margin, which shall be fixed at a rate of 2.00% for thefirst two quarters following the closing of the credit facility.  After that period, the applicable margin willbe adjusted quarterly based on the Partnership’s ratio of funded debt to EBITDA(as defined in the credit agreement). The Partnership is also required to pay a commitment fee equal to theapplicable rate (as defined in the credit agreement) times the actual dailyamount by which the aggregate revolver commitments exceed the sum of (i) theoutstanding amount of revolver loans plus (ii) the outstanding amount ofletters of credit obligations.  Thecommitment fee is due and payable quarterly in arrears on the last business dayof each March, June, September and December.

 

In connectionwith the credit facility, the Partnership is subject to a number ofrestrictions on its business, including restrictions on its ability to grantliens on assets, merge, consolidate or sell assets, incur indebtedness (otherthan subordinate indebtedness), make acquisitions, engage in other businesses,enter into capital or operating leases, engage in transactions with affiliates,make distributions on equity interests and other usual and customary covenants.  In addition, MarkWest Energy Partners issubject to certain financial maintenance covenants, including ratios of totaldebt to EBITDA, total senior secured debt to EBITDA, EBITDA to interest and aminimum net worth

 

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requirement.  Failure to comply with the provisions of anyof these covenants could result in acceleration of the debt and other financialobligations.

 

Concurrent withthe amendment of the credit facility, in October 2004, the Partnership issued$225.0 million in senior notes at a fixed rate of 6.875% and with a maturitydate of November 1, 2014.  Subject tocompliance with certain covenants, the Partnership may issue additional notesfrom time to time under the indenture.  Interest on the notes accrue at the rate of 6.875% per year and arepayable semi-annually in arrears on May 1 and November 1, commencing on May 1,2005.  MarkWest Energy Partners mayredeem some or all of the notes at any time on or after November 1, 2009 atcertain redemption prices together with accrued and unpaid interest to the dateof redemption, and the Partnership may redeem all of the notes at any timeprior to November 1, 2009 at a make-whole redemption price.  In addition, prior to November 1, 2007, thePartnership may redeem up to 35% of the aggregate principal amount of the noteswith the proceeds of certain equity offerings at a certain redemptionprice.  If MarkWest Energy Partners sellscertain assets and does not reinvest the proceeds or repay senior indebtedness,or if it experiences specific kinds of changes in control, it must offer torepurchase notes at a specified price. Each of its existing subsidiaries, other than MarkWest Energy FinanceCorporation, has guaranteed the notes initially and so long as such subsidiaryguarantees any of the other debt.  Notall of the Partnership’s future subsidiaries will have to becomeguarantors.  The notes are seniorunsecured obligations with equal in right of payment with all of the existingand future senior debt.  These notes aresenior in right of payment to all of the Partnership’s future subordinated debtbut effectively junior in right of payment to its secured debt to the extent ofthe assets securing the debt, including its obligations in respect of the bankcredit facility.  Borrowings under thesenotes were used to pay down the outstanding debt under the credit facility.

 

On October 31, 2004, after theclosing of the senior indentured notes and after the Partnership had amendedand restated the credit agreement, the Partnership had $225.0 million of seniorindebtedness outstanding, comprised of $225.0 million unsecured senior notes ata fixed rate of 6.875%.

 

Cash generated from operations,borrowings under the credit facility and funds from the private and publicequity offerings are the Partnership’s primary source of liquidity. We believethat funds from these sources will be sufficient to meet both the Partnership’sshort-term and long-term working capital requirements and anticipated capitalexpenditures.  The Partnership’s abilityto fund additional acquisitions will likely require the issuance of additionalcommon units, the expansion of the credit facility, additional debt financingor a combination of all three.  Inthe event that the Partnership needs or desires to raise additional capital, itcannot be sure that additional funds will be available at times or on termsfavorable to the Partnership.

 

The Partnership’s ability to paydistributions to its unitholders and to fund planned capital expenditures andto make acquisitions will depend upon its future operating performance, whichwill be affected by prevailing economic conditions in the industry andfinancial, business and other factors, some of which are beyond our control.

 

ThePartnership’s largest customer is MarkWest Hydrocarbon, Inc. Consequently,matters affecting our business and financial condition—including ouroperations, management, customers, vendors, and the like—have the potential toimpact, both positively and negatively, the Partnership’s liquidity.

 

Sustaining capital expenditures,which are expenditures made to replace partially or fully depreciated assets inorder to maintain the existing operating capacity of the assets and to extendtheir useful lives, are estimated to approximate $0.7 million for thePartnership for the remainder of 2004. For the nine months ended September 30,2004, these expenditures were $1.0 million.

 

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***Total Contractual cash obligations***

 

Asummary of our total contractual cash obligations as of September 30, 2004, isas follows (in thousands):

 
| **Type of Obligation** | ** ** | **Total  Obligation** | ** ** | **Due in  2004-2005** | ** ** | **Due in  2006-2007** | ** ** | **Thereafter** | ** ** |
|------------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|----------------|------------|
| Operating Leases       |       | $                     | 14,050     |                  | $          | 5,600                 |       | $              | 4,448      |   | $ | 4,002 |   |
| Debt                   |       | 197,500               |       | —                |       | —                |       | 197,500        |       |
| Total                  |       | $                     | 211,550    |                  | $          | 5,600                 |       | $              | 4,448      |   | $ | 201,502 |   |

 

***Cash Flows***

 
| ** **                                 | ** ** | **Nine Months Ended September 30,** | ** ** |
|--------------------------------------------|------------|-------------------------------------|------------|
| ** **                                 | ** ** | **2004**                            | ** ** | **2003** | ** ** |
| ** **                                 | ** ** | **(in thousands)**                  | ** ** |
| Net cash  provided by operating activities |       | $                                   | 17,457     |   | $ | 3,153 |   |
| Net cash used in  investing activities     |       | $                                   | (272,039   | ) | $ | (17,771 | ) |
| Net cash  provided by financing activities |       | $                                   | 234,696    |   | $ | 15,677 |   |

 

Net cash****providedby operating activities for the nine months ended September 30, 2004, increasedrelative to the same period in the prior year principally due to an increase inaccounts payable and accrued liabilities as a result of the 2003 and 2004acquisitions.

 

Net cash used ininvesting activities for the nine months ended September 30, 2004, increasedrelative to the same period in the prior year primarily due to the Partnership’sacquisition of the East Texas System in July 2004 for $240.6 million.  Additionally, we invested $11.8 million inmarketable securities.

 

Net cash provided byfinancing activities for the nine months ended September 30, 2004, wasprimarily attributable to equity financings and borrowings under ourPartnership’s credit facility.  InJanuary 2004, the Partnership completed a secondary public offering generatingnet proceeds of $44.9 million in 2004. The proceeds were used to pay down the outstanding debt.  The Partnership also amended and restated itscredit facility in July 2004 to increase its total borrowing capacity to $315.0million.  MarkWest Energy Partnersborrowed $200.8 million under this credit facility to partially finance itsEast Texas System acquisition.  In July2004, the Partnership completed a private placement of 1,304,438 of commonunits to a group of institutional investors, generating total net proceeds of$44.9 million.  These funds were alsoused to partially finance the East Texas System acquisition.  In addition, the Partnership raised netproceeds of $97.8 million through a public offering of 2,323,609 common unitsin September 2004.  Proceeds from thisoffering were used to reduce our outstanding indebtedness.  Additionally, we paid dividends of $5.3million and MarkWest Energy Partners paid distributions to its unitholders of$9.6 million.

 

***Recent Accounting Pronouncements***

 

On March 31, 2004, the Emerging Issues Task Forceissued EITF No. 03-6 which clarifies the computation of earnings per share inSFAS No. 128, for companies that have issued securities other than common stockthat entitle the holder to participate in the company’s declared dividends andearnings.  The consensus states that securities should be included inbasic earnings per share calculations when the holder is entitled to receivedividends rather than if the holder is entitled to receive earnings or valueupon redemption of the securities or liquidation of assets.  The effectivedate of EITF No. 03-6 is the first fiscal period beginning after March 31,2004, and requires restatement of prior period information.  Implementation of the consensus had no effecton the financial results and resulted in no change in earnings per share forthe three month and nine month periods ending September 30, 2004, and 2003.

 

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**Forward-LookingInformation**

 

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

 

These forward-lookingstatements are made based upon management’s current plans, expectations,estimates, assumptions and beliefs concerning future events impacting us andtherefore involve a number of risks and uncertainties. We caution thatforward-looking statements are not guarantees and that actual results coulddiffer materially from those expressed or implied in the forward-lookingstatements as a result of certain factors as more fully discussed under theheading “Risk Factors” contained in our annual report on Form 10-K filed onMarch 15, 2004 with the Securities and Exchange Commission (File No. 001-31239)for our fiscal year ended December 31, 2003. Forward-looking statements includestatements relating to, among other things:

 

•                  Our expectations regardingMarkWest Energy Partners, L.P.

•                  The continued growth of MarkWestEnergy Partners, L.P.

•                  Our ability to amend certainproducer contracts.

•                  Our ability to increasefee-based contract volumes.

•                  Our expectations regardingnatural gas and NGL production and prices.

•                  Our ability to manage ourcommodity price risk.

•                  Our ability to maximize thevalue of our NGL output.

 

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.

•                  Theavailability and prices of raw natural gas supply.

•                  Ourability to negotiate favorable marketing agreements.

•                  Therisks that third party natural gas exploration and production activities willnot 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.

 

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.

 

In addition, certain ofthe Partnership’s pipelines could in the future become subject to thejurisdiction of the Federal Energy Regulatory Commission, or FERC, dependingupon possible changes in the factual circumstances upon which each pipeline’sjurisdictional status is based.  Such achange could adversely affect the terms of service, rates and revenues of suchpipelines.

 

The Michigan CrudePipeline is not currently subject to the jurisdiction of the FERC.  If a shipper sought to challenge thejurisdictional status of this pipeline, however, FERC could determine thattransportation on this pipeline is within its jurisdiction under the InterstateCommerce Act, thereby requiring the Partnership to file a tariff and cost-basedrates for such transportation with FERC. While no shipper has filed a formal complaint, one shipper on theMichigan Crude Pipeline has contacted FERC about the transportation rates andquestion the jurisdictional status of the pipeline.  FERC requested that MarkWest Energy Partnersand the shipper resolve the dispute.  Ifthe Partnership is unable to successfully resolve this dispute or any futuredispute over the jurisdictional status of the Michigan Crude Pipeline, it couldbecome subject to FERC regulation, and the cost of compliance with that

 

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regulation could adversely affect our profitability.

 

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#### **Item3.  Quantitative and QualitativeDisclosures about Market Risk**

 

Market risk includes the risk of loss arising fromadverse changes in market rates and prices. We face market risk from commodityprice variations and also incur, to a lesser extent, credit risks and risksrelated to interest rate variations.

 

***Commodity Price Risk***

 

We marketnatural gas and NGL products.  Inaddition, through our consolidated subsidiary, MarkWest Energy Partners, we areengaged in the gathering processing and transmission of natural gas, thetransportation, fractionation and storage of NGLs and the gathering andtransportation of crude oil.  Ourproducts are commodities that are subject to price risk resulting from materialchanges in response to fluctuations in supply and demand, general economicconditions and other market conditions, such as weather patterns, over which wehave no control.

 

Our primary risk management objective is to reducevolatility in our cash flows.  Ourhedging approach includes statistical methods that analyze momentum and averagepricing over time, and various fundamental data such as industry inventories,industry production, demand and weather. A committee, which includes members ofsenior management, oversees all of our hedging activity.

 

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

 

We enter OTC swaps with financial institutions andother energy company counterparties. We conduct a standard credit review oncounterparties and have agreements containing collateral requirements wheredeemed necessary. We use standardized swap agreements that allow for offset ofpositive and negative exposures.  Netcredit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements and NYMEXpositions.

 

The use of financial instruments may expose us to therisk of financial loss in certain circumstances, including instances when (i)NGLs do not trade at historical levels relative to crude oil, (ii) salesvolumes are less than expected requiring market purchases to meet commitments,or (iii) our OTC counterparties fail to purchase or deliver the contractedquantities of natural gas, NGLs, or crude oil or otherwise fail to perform. Tothe extent that we engage in hedging activities, we may be prevented fromrealizing the benefits of favorable price changes in the physical market.  However, we are similarly insulated againstdecreases in such prices.

 

In addition to these risk management tools, we utilizeour NGL product storage facilities and contracts for third-party storage tobuild product inventories during lower-demand periods for resale duringhigher-demand periods.

 

*NGLPrice Risk*

 

Within our NGL marketingsegment, our price risk varies by contract as well as by spot market prices forboth NGL and natural gas commodities. The Appalachian producers compensate us for providing midstream servicesunder the following contract types:

 

•                  Under “keep-whole” contracts, wetake title to and sell the NGLs produced in our processing operations. We alsoreimburse or “keep whole” the producers for the Btu content of the NGLs removedthrough the re-delivery to the producers of an equivalent amount (on a Btubasis) of dry natural gas.  Keep-wholecontracts therefore expose us to NGL product price risk (on the sales side) andnatural gas price risk (on the purchase or reimbursement side).  Generally, the value of the NGLs extracted isgreater than the cost of replacing those Btus with dry gas, resulting inpositive operating margins under these contracts.  In the event natural gas becomes moreexpensive, on a Btu equivalent basis, than NGL products, in conjunction withour operating expenses, the cost of keeping the producer “whole” results

 

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in operatinglosses.  The spread between the NGLproduct sales price and the purchase price of natural gas with an equivalentBtu content is called the “frac spread”.

 

•                  Under “percent-of-proceeds”contracts, the Partnership takes title to the NGLs produced in its processingoperations, sells the NGLs to third parties and pays the producer a specifiedpercentage of the proceeds received from the sales.  Percent-of-proceeds contracts thereforeexpose the Partnership to NGL product price risk.  All of the Michigan processing business isalso governed by percent-of-proceeds contracts.

 

Our consolidatedsubsidiary, MarkWest Energy Partners, is also subject to NGL price risk.  For the nine months ended September 30, 2004,approximately 39% of the Partnership’s business (as measured by gross margin,which is defined as revenue less purchased product cost) was directly subjectto natural gas and NGL product price risk. This includes the entire gross margin from the Partnership’s businessbased on percent-of-index contracts, percent-of-proceeds contracts andkeep-whole contracts.  Regarding the 19%of the gross margin governed by keep-whole contracts, MarkWest Energy Partnersactively manages the related commodity price risk exposure, to the extentpossible, by not operating its Arapaho processing plant in Oklahoma during lowprocessing margin environments and through our ability to reject or recoverethane in Carthage.  See relateddiscussion in Item 2. Management’s Discussion and Analysis”.

 

As of September 30,2004, we had contracts in place to manage our NGL product price risk asfollows:

 
| ** **                    | ** ** | **Year Ending December 31,** | ** ** |
|-------------------------------|------------|------------------------------|------------|
| ** **                    | ** ** | **2004**                     | ** ** | **2005** | ** ** |
| **Hedged  NGL product price** |       |                         |       |   |   |
| NGL gallons                   |       | 8,778,000                    |       | 8,274,000 |   |
| $/gallons                     |       | $                            | 0.88       |   | $ | 0.86 |   |
|                               |            |                              |            |  |  |  |  |

 

Asof September 30, 2004, we hedged our natural gas price risk via pre-purchasesas follows:

 
| ** **                         | ** ** | **Year Ending December 31** | ** ** |
|------------------------------------|------------|-----------------------------|------------|
| ** **                         | ** ** | **2004**                    | ** ** | **2005** | ** ** |
| **Hedged  Natural Gas Purchases:** |       |                        |       |   |   |
| MMBtu                              |       | 850,929                     |       | 802,071 |   |
| $/MMBtu                            |       | $                           | 5.56       |   | $ | 5.56 |   |
|                                    |            |                             |            |  |  |  |  |

 

***MarkWest Energy Partners***

 

ThePartnership hedges its natural gas price risk in Texas (part of our Pinnacleacquisition) by entering into fixed-for-float price swaps or buying puts.  As of September 30, 2004, the Partnershiphedged its Texas natural gas price risk via swaps as follows:

 
| ** ** | ** ** | **Year Ending December 31,** | ** ** |
|------------|------------|------------------------------|------------|
| ** ** | ** ** | **2004**                     | ** ** | **2005** | ** ** |
|       |       |                         |       |   |   |
| MMBtu      |       | 30,500                       |       | 182,500 |   |
| $/MMBtu    |       | $                            | 4.57       |   | $ | 4.26 |   |
|            |            |                              |            |  |  |  |  |

 

Asof September 30, 2004, MarkWest Energy Partners also had hedged its Texasnatural gas price risk via puts as follows:

 
| ** **              | ** ** | **Year Ending December 31,** | ** ** |
|-------------------------|------------|------------------------------|------------|
| ** **              | ** ** | **2004**                     | ** ** | **2005** | ** ** |
|                    |       |                         |       |   |   |
| MMBtu                   |       | 61,000                       |       | — |   |
| Strike price  ($/MMBtu) |       | $                            | 4.00       |   | $ | — |   |
|                         |            |                              |            |  |  |  |  |

 

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Additionally, at September 30, 2004, the Partnershiphad hedged its Oklahoma natural gas basis risk via swap as follows:

 
| ** ** | ** ** | **Year Ending December 31,** | ** ** |
|------------|------------|------------------------------|------------|
| ** ** | ** ** | **2004**                     | ** ** | **2005** | ** ** |
|       |       |                         |       |   |   |
| MMBtu      |       | 951,000                      |       | 900,000 |   |
| ($/MMBtu)  |       | $                            | (0.035     | ) | $ | (0.035 | ) |
|            |            |                              |            |  |  |  |  |

 

*InterestRate Risk*

 

The Partnership isexposed to changes in interest rates, primarily as a result of its long-termdebt under the credit facility with floating interest rates.  The Partnership makes use of interest rateswap and collar agreements to adjust the ratio of fixed and floating rates(LIBOR plus an applicable margin) in the debt portfolio.

 

Asof September 30, 2004, the Partnership was a party to interest rate swapagreements to fix interest rates on debt of $8.0 million at 3.84% through May2005 and $25.0 million at 3.33% through November 2006 (currently $33.0 millionwith a weighted average interest rate of 3.46%).  In addition, the Partnership is a party to aninterest-rate collar agreement on $20.0 million of debt with a maximum rate of3.33% through May 2005, and a minimum rate of 1.25% through August 2004, 1.30%through November 2004, 2.10% through February 2005 and 2.60% through May 2005.

 

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##### **Item 4.**Controls andProcedures

 

Attached as exhibits 31.1, 31.2 and 31.3 to thisQuarterly Report are certifications of our principal executive and accountingofficers (who we refer to in this periodic report as our Certifying Officers)as required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002(the “Section 302 Certifications”). This portion of our Quarterly Report onForm 10-Q discloses the results of our evaluation of our disclosure controlsand procedures as of September 30, 2004, referred to in paragraphs (4) and (5)of the Section 302 Certifications and should be read in conjunction with theSection 302 Certifications for a more complete understanding of the topicspresented.

 

We maintain disclosure controls and procedures that aredesigned to ensure that information required to be disclosed by us in thereports that we file or submit to the Securities and Exchange Commission underthe Securities Exchange Act of 1934, as amended, is recorded, processed,summarized and reported within the time periods specified by the Commission’srules and forms, and that information is accumulated and communicated to ourmanagement, including our Certifying Officers, as appropriate to allow timelydecisions regarding required disclosure. Our management evaluated, with theparticipation of our Certifying Officers, the effectiveness of our disclosurecontrols and procedures as of September 30, 2004, pursuant to Rule 13a-15(b)under the Exchange Act.  Based upon that evaluation, our CertifyingOfficers concluded that as of September 30, 2004, our disclosure controls andprocedures were effective.

 

Nevertheless, we are continuing to conduct an internalreview under the supervision and with the participation of our management andour Certifying Officers of the effectiveness of the design and operation of ourdisclosure controls and procedures.  Thepurpose of such review is to identify and establish enhancements to ourdisclosure controls and procedures that can help prevent any potentialmisstatements or omissions in our consolidated financial statements.  Such enhancements are also focused onassisting our management in evaluating the effectiveness of our internalcontrols over financial reporting as required by Section 404 of theSarbanes-Oxley Act of 2002 commencing with our fiscal year ending December 31,2004.

 

In performance of the audit for the fiscal year endedDecember 31, 2003, the Partnership’s independent auditors at that time,PricewaterhouseCoopers LLP (“PwC”), identified to management and the AuditCommittee certain deficiencies in our internal accounting controls which,considered collectively, could have constituted a material weakness in ourinternal controls when evaluated against the compliance standards under Section404 of the Sarbanes-Oxley Act of 2002, had it been applicable and in effect atthat time. Specific deficiencies identified by PwC included a possibleinsufficiency in the personnel resources available to adequately maintain ourfinancial reporting obligation as a public company; inadequate implementationof uniform controls over certain acquired entities and operations; inadequatecontrol over classification of certain fixed asset balances and processes foraccrual of certain accounts payable; and the potential need for separation ofcertain duties between payroll and other accounting personnel.

 

Managementhas assigned a high priority to both the short-term and long-term improvementand remediation actions to address and correct any potential weaknesses in thedeficiencies noted by PwC. Under the supervision and with the participation ofour management and Certifying Officers regarding the effectiveness of thedesign and operation of our disclosure controls and processes, we havedocumented and implemented numerous internal control improvements throughoutthe organization to address the deficiencies noted by PwC, as well as othersidentified by employees and management during the course of our internal reviewprocedures.

 

Management believes it will be able to complete allinternal control documentation and control design assessment procedures by theend of the fourth quarter 2004. However, the frequency of the operation of keycontrols implemented or modified during the fourth quarter 2004 may limitmanagement’s ability to complete its tests of operating effectiveness of keyinternal controls.  As our controlsystems are tested, we will continue to implement changes to our policies,procedures, systems and personnel as necessary to endeavor to comply with thecontrol standards established under Section 404 of the Sarbanes-Oxley Act of2002.

 

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**PART II—OTHER INFORMATION**

 

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

 

Reference is made to Note13 of our Consolidated Financial Statements in Part I Item 1 of this Form 10-Q,which is incorporated herein by reference.

 

**Item 6.  Exhibits**

 
| 2.1(1)  |   | Asset Purchase and Sale  Agreement and addendum, thereto, dated as of July 1, 2004 by and between  American Central Eastern Texas Gas Company Limited Partnership, ACGC  Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.                                                                                                                                                                                                                |
|---------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 4.1(1)  |   | Unit Purchase Agreement  dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest  Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne  Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne  Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR  RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and  Energy Income and Growth Fund, as Purchasers. |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 4.2(1)  |   | Registration Rights  Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and  each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income  Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master  Trust, Tortoise Energy Infrastructure Corporation and Energy Income and  Growth Fund.                                                                                                                       |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.1    |   | Certification of the  Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange  Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                          |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.2    |   | Certification of the  Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange  Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                          |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.3    |   | Certification of the  Chief Accounting Officer pursuant to Rule 13a-14(a) of the Securities  Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of  2002.                                                                                                                                                                                                                                                                                        |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 32.1    |   | Certification of the  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 the  Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                 |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 32.3    |   | Certification of the  Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 99.1(1) |   | Second Amended and  Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy  Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as  Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital  Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe  Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.                                                         |
|    |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 99.2(1) |   | First Amendment to the  Second Amended and Restated Credit Agreement dated as of August 20, 2004,  among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy  Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent,  Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation  Agent and Societe Generale, as Documentation Agent.                                                                          |

 

38

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|    |   |                                                                                                                                                              |
|---------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 99.3(2) |   | Firm Gas Processing  Agreement (Dwale) entered into on September 23, 2004 between Equitable  Production Company and MarkWest Hydrocarbon, Inc.                    |
|    |   |                                                                                                                                                              |
| 99.4(2) |   | Sale and Purchase of  Natural Gas Agreement entered into on September 23, 2004 between Equitable  Production Company and MarkWest Hydrocarbon, Inc.               |
|    |   |                                                                                                                                                              |
| 99.5(2) |   | Netting, Financial  Responsibility and Security Agreement entered into on September 23, 2004  between Equitable Production Company and MarkWest Hydrocarbon, Inc. |

 

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(1)  Filed as an exhibit to the Registrants’ Form8-K/A dated July 30, 2004 and filed on October 12, 2004.

(2)  Portions of the agreement have been redacted,as we will request confidential treatment from the Securities and ExchangeCommission.

 

39

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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 22, 2004 | /s/ James G. Ivey        |                       |
|                    | James G. Ivey            |                       |
|                    | Chief Financial  Officer |                       |
|                         |                          |                            |  |

 

40

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| **Exhibit  Number** | ** ** | **Exhibit Index**                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|---------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 2.1(1)              |       | Asset Purchase and Sale  Agreement and addendum, thereto, dated as of July 1, 2004 by and between  American Central Eastern Texas Gas Company Limited Partnership, ACGC  Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.                                                                                                                                                                                                                |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 4.1(1)              |       | Unit Purchase Agreement  dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest  Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne  Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne  Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR  RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and  Energy Income and Growth Fund, as Purchasers. |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 4.2(1)              |       | Registration Rights  Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and  each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income  Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master  Trust, Tortoise Energy Infrastructure Corporation and Energy Income and  Growth Fund.                                                                                                                       |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.1                |       | Certification of the  Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange  Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                          |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.2                |       | Certification of the  Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange  Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                          |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 31.3                |       | Certification of the  Chief Accounting Officer pursuant to Rule 13a-14(a) of the Securities  Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of  2002.                                                                                                                                                                                                                                                                                        |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 32.1                |       | Certification of the  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 the  Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                 |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 32.3                |       | Certification of the  Chief Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 99.1(1)             |       | Second Amended and  Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy  Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as  Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital  Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe  Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.                                                         |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 99.2(1)             |       | First Amendment to the  Second Amended and Restated Credit Agreement dated as of August 20, 2004,  among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy  Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent,  Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent  and Societe Generale, as Documentation Agent.                                                                          |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 99.3(2)             |       | Firm Gas Processing  Agreement (Dwale) entered into on September 23, 2004 between Equitable  Production Company and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                           |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| 99.4(2)             |       | Sale and Purchase of  Natural Gas Agreement entered into on September 23, 2004 between Equitable  Production Company and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                      |

 

41

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| 99.5(2) |   | Netting, Financial  Responsibility and Security Agreement entered into on September 23, 2004  between Equitable Production Company and MarkWest Hydrocarbon, Inc. |
|---------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

----

(1)  Filedas an exhibit to the Registrants’ Form 8-K/A dated July 30, 2004 and filed onOctober 12, 2004.

(2)  Portions of the agreement have been redacted, as wewill request confidential treatment from the Securities and ExchangeCommission.

 

42

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