**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-Q**

 
| ý |   | **QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)**

**OF THE SECURITIES EXCHANGE ACT OF  1934** |
|--------|--------|---------------------------------------------------------------------------------------------------|

 

**For the quarterly period ended September 30, 2001**

 

**OR**

 
| **o** |   | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**

**SECURITIES EXCHANGE ACT OF 1934** |
|-------|--------|----------------------------------------------------------------------------------------------------|

 

**For the transition period from                                   to                                           **

 

**Commission File Number 1-11566**

 

**MARKWEST HYDROCARBON, INC.**

(Exactname of registrant as specified in its charter)

 

| **Delaware**                                                              |   | **84-1352233**                     |
|---------------------------------------------------------------------------|--------|------------------------------------|
| (State or other  jurisdiction of incorporation or organization)           |   | (IRS Employer  Identification No.) |
|                                                                      |
| **155 Inverness Drive West, Suite  200, Englewood, CO  80112-5000**  |
|  (Address  of principal executive offices)                           |
|                                                                      |
| Registrant’s telephone number, including area code: **303-290-8700** |
|                                                                      |   |                               |

** **

Indicate by check mark whether the registrant (1) has filed all reportsrequired to be filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject to suchfiling requirements for the past 90 days.

Yesý     Noo

 

The registrant had 8,486,724 shares of common stock, $.01 per share parvalue, outstanding as of September 30, 2001.

 

 

 
|                                  |                                                                                                                             |
|---------------------------------------|----------------------------------------------------------------------------------------------------------------------------------|
| **PART I—FINANCIAL INFORMATION** |
|                                  |                                                                                                                             |
| Item 1.                          | Consolidated Financial  Statements                                                                                               |
|                                  | Consolidated Balance Sheet at September 30, 2001  and December 31, 2000                                                          |
|                                  | Consolidated Statement of  Operations for the Three and Nine Months Ended September 30, 2001 and  2000                      |
|                                  | Consolidated Statement of  Cash Flows for the Three and Nine Months Ended September 30, 2001 and  2000                      |
|                                  | Consolidated Statement of  Changes in Shareholder’s Equity for the Three and Nine Months Ended September  30, 2001 and 2000 |
|                                  | 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                                                                      |
|                                  |                                                                                                                             |
| **PART II—OTHER INFORMATION**    |
|                                  |                                                                                                                             |
| Item 1.                          | Legal Proceedings                                                                                                                |
| Item 6.                          | Exhibits and Reports on Form  8-K                                                                                                |
|                                  |                                                                                                                             |
| **SIGNATURE**                         |
|                                  |                                                                                                                             |
|                                       |                                                                                                                                  |  |  |

#### ** **

| **Glossary  of Terms**                                                        |
|-------------------------------------------------------------------------------|
|                                                                          |   |   |
| Bbls                                                                          |   | barrels |
| Bcf                                                                           |   | billion cubic feet of natural gas |
| Btu                                                                           |   | British thermal units, an energy measurement |
| EBITDA                                                                        |   | earnings before gain on sale, interest income,  interest expense, income taxes, depreciation, depletion and amortization; a  cash flow financial measure commonly used in the oil and gas industry |
| MM                                                                            |   | million |
| Mcf                                                                           |   | thousand cubic feet of natural gas |
| Mcfd                                                                          |   | thousand cubic feet of natural gas per day |
| Mcfe                                                                          |   | thousand cubic feet of natural gas equivalent |
| Mcfed                                                                         |   | thousand cubic feet of natural gas equivalent per  day |
| MMBtu                                                                         |   | million British thermal units, an energy measurement |
| MMcf                                                                          |   | million cubic feet of natural gas |
| MMcfd                                                                         |   | million cubic feet of natural gas per day |
| NGL                                                                           |   | natural gas liquids, such as propane, butanes and  natural gasoline |
|                                                                          |   |   |
| One barrel of oil or NGL is the energy equivalent of  six Mcf of natural gas. |

 

 

## **PARTI—FINANCIAL INFORMATION**

**Item1.  Consolidated Financial Statements**

 

**MARKWEST HYDROCARBON, INC.**

**CONSOLIDATEDBALANCE SHEET**

**(UNAUDITED)**

**(000s, except share data)**

** **
|                                                                                                               |   | **September 30,** |    | **December 31,** |   |
|--------------------------------------------------------------------------------------------------------------------|--------|-------------------|---------|------------------|--------|
| **ASSETS**                                                                                                         |   | **2001**          |    | **2000**         |   |
| Current assets:                                                                                                    |   |              |    |             |   |
| Cash and cash equivalents                                                                                          |   | $                 | 2,437   |             | $      | 934 |   |
| Receivables                                                                                                        |   | 15,931            |    | 36,695           |   |
| Inventories                                                                                                        |   | 7,322             |    | 8,058            |   |
| Prepaid  feedstock                                                                                                 |   | 7,276             |    | —           |   |
| Risk management  asset                                                                                             |   | 6,506             |    | —           |   |
| Other assets                                                                                                       |   | 1,247             |    | 913              |   |
| Total current  assets                                                                                              |   | 40,719            |    | 46,600           |   |
|                                                                                                               |   |              |    |             |   |
| Property and  equipment:                                                                                           |   |              |    |             |   |
| Gas processing,  gathering, storage and marketing equipment                                                        |   | 105,614           |    | 97,311           |   |
| Oil and gas  properties and equipment                                                                              |   | 108,652           |    | 18,037           |   |
| Land, buildings  and other equipment                                                                               |   | 6,546             |    | 6,463            |   |
| Construction in  progress                                                                                          |   | 8,011             |    | 6,241            |   |
|                                                                                                               |   | 228,823           |    | 128,052          |   |
| Less:  accumulated depreciation, depletion and amortization                                                        |   | (34,117           | )       | (27,833          | )      |
| Total property  and equipment, net                                                                                 |   | 194,706           |    | 100,219          |   |
|                                                                                                               |   |              |    |             |   |
| Risk management  asset                                                                                             |   | 1,875             |    | —           |   |
| Intangible  assets, net of accumulated amortization of $119 and $708, respectively                                 |   | 2,828             |    | 468              |   |
|                                                                                                               |   |              |    |             |   |
| Total assets                                                                                                       |   | $                 | 240,128 |             | $      | 147,287 |   |
|                                                                                                               |   |              |    |             |   |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                     |   |              |    |             |   |
| Current  liabilities:                                                                                              |   |              |    |             |   |
| Accounts payable                                                                                                   |   | $                 | 19,307  |             | $      | 17,713 |   |
| Accrued  liabilities                                                                                               |   | 7,669             |    | 13,740           |   |
| Risk management  liability                                                                                         |   | 2,621             |    | —           |   |
| Total current  liabilities                                                                                         |   | 29,597            |    | 31,453           |   |
|                                                                                                               |   |              |    |             |   |
| Deferred income  taxes                                                                                             |   | 43,832            |    | 11,240           |   |
| Long-term debt                                                                                                     |   | 101,000           |    | 43,000           |   |
| Risk management  liability                                                                                         |   | 400               |    | —           |   |
| Commitments and  contingencies (see Note 6)                                                                        |   | —            |    | —           |   |
|                                                                                                               |   |              |    |             |   |
| Stockholders’  equity:                                                                                        |   |              |    |             |   |
| Preferred stock,  par value $0.01, 5,000,000 shares authorized, 0 shares outstanding                               |   | —            |    | —           |   |
| Common stock,  par value $0.01, 20,000,000 shares authorized, 8,563,919 and 8,561,206 shares  issued, respectively |   | 87                |    | 86               |   |
| Additional  paid-in capital                                                                                        |   | 42,549            |    | 42,471           |   |
| Retained  earnings                                                                                                 |   | 20,942            |    | 19,679           |   |
| Accumulated  other comprehensive income                                                                            |   | 2,197             |    | —           |   |
| Treasury stock,  77,195 and 104,093 shares, respectively                                                           |   | (476              | )       | (642             | )      |
| Total  stockholders’ equity                                                                                   |   | 65,299            |    | 61,594           |   |
|                                                                                                               |   |              |    |             |   |
| Total  liabilities and stockholders’ equity                                                                   |   | $                 | 240,128 |             | $      | 147,287 |   |

 

The accompanying notesare an integral part of these financial statements.

 

**CONSOLIDATEDSTATEMENT OF OPERATIONS**

**(UNAUDITED)**

**(000s, except per share data)**

 
|                                                            |   | **For the three months ended** |   | **For the nine months ended** |   |
|-----------------------------------------------------------------|--------|--------------------------------|--------|-------------------------------|--------|
|                                                            |   | **September 30,**              |   | **September 30,**             |   |
|                                                            |   | **2001**                       |   | **2000**                      |   | **2001** |   | **2000** |   |
| Revenue:                                                        |   |                           |   |                          |   |   |   |   |   |
| Gathering,  processing and marketing                            |   | $                              | 28,309 |                          | $      | 55,845 |   | $ | 142,368 |   | $ | 139,329 |   |
| Exploration and  production                                     |   | 4,084                          |   | 1,461                         |   | 9,120 |   | 3,279 |   |
| Total revenue                                                   |   | 32,393                         |   | 57,306                        |   | 151,488 |   | 142,608 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Operating  expenses:                                            |   |                           |   |                          |   |   |   |   |   |
| Cost of sales                                                   |   | 21,921                         |   | 46,351                        |   | 120,596 |   | 109,643 |   |
| Operating  expenses                                             |   | 4,946                          |   | 4,354                         |   | 13,943 |   | 12,244 |   |
| General and  administrative expenses                            |   | 1,906                          |   | 2,173                         |   | 6,189 |   | 6,031 |   |
| Depreciation,  depletion and amortization                       |   | 3,295                          |   | 1,427                         |   | 6,700 |   | 4,323 |   |
| Total operating expenses                                        |   | 32,068                         |   | 54,305                        |   | 147,428 |   | 132,241 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Income from  operations                                         |   | 325                            |   | 3,001                         |   | 4,060 |   | 10,367 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Other income and  expense:                                      |   |                           |   |                          |   |   |   |   |   |
| Interest income                                                 |   | 32                             |   | 24                            |   | 114 |   | 77 |   |
| Interest expense                                                |   | (974                           | )      | (820                          | )      | (2,234 | ) | (2,222 | ) |
| Gain on sale of  assets                                         |   | —                         |   | —                        |   | — |   | 1,000 |   |
| Other income  (expense)                                         |   | (4                             | )      | (81                           | )      | (253 | ) | 22 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Income (loss)  before income taxes                              |   | (621                           | )      | 2,124                         |   | 1,687 |   | 9,244 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Provision  (benefit) for income taxes:                          |   |                           |   |                          |   |   |   |   |   |
| Current                                                         |   | (120                           | )      | 439                           |   | 348 |   | 1,957 |   |
| Deferred                                                        |   | (307                           | )      | 360                           |   | 76 |   | 1,601 |   |
| Provision for  income taxes                                     |   | (427                           | )      | 799                           |   | 424 |   | 3,558 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Net income  (loss)                                              |   | $                              | (194   | )                             | $      | 1,325 |   | $ | 1,263 |   | $ | 5,686 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Basic earnings  (loss) per share of common stock                |   | $                              | (0.02  | )                             | $      | 0.16 |   | $ | 0.15 |   | $ | 0.67 |   |
| Earnings (loss)  per share assuming dilution                    |   | $                              | (0.02  | )                             | $      | 0.16 |   | $ | 0.15 |   | $ | 0.67 |   |
|                                                            |   |                           |   |                          |   |   |   |   |   |
| Weighted average  number of outstanding shares of common stock: |   |                           |   |                          |   |   |   |   |   |
| Basic                                                           |   | 8,479                          |   | 8,450                         |   | 8,473 |   | 8,451 |   |
| Assuming  dilution                                              |   | 8,501                          |   | 8,489                         |   | 8,500 |   | 8,475 |   |

 

The accompanying notesare an integral part of these financial statements.

**CONSOLIDATEDSTATEMENT OF CASH FLOWS**

**(UNAUDITED)**

**(000s)**

 
|                                                             |   | **For the three months** |   | **For the nine months** |   |
|------------------------------------------------------------------|--------|--------------------------|--------|-------------------------|--------|
|                                                             |   | **ended September 30,**  |   | **ended September 30,** |   |
|                                                             |   | **2001**                 |   | **2000**                |   | **2001** |   | **2000** |   |
| Cash flows from  operating activities:                           |   |                     |   |                    |   |   |   |   |   |
| Net income                                                       |   | $                        | (194   | )                       | $      | 1,325 |   | $ | 1,263 |   | $ | 5,686 |   |
| Add income items  that do not affect working capital:            |   |                     |   |                    |   |   |   |   |   |
| Depreciation,  depletion and amortization                        |   | 3,295                    |   | 1,427                   |   | 6,700 |   | 4,323 |   |
| Deferred income  taxes                                           |   | (307                     | )      | 360                     |   | 76 |   | 1,601 |   |
| Gain on sale of  assets                                          |   | —                   |   | —                  |   | — |   | (1,000 | ) |
| Other                                                            |   | (53                      | )      | (12                     | )      | (49 | ) | (148 | ) |
|                                                             |   | 2,741                    |   | 3,100                   |   | 7,990 |   | 10,462 |   |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Adjustments to  working capital:                                 |   |                     |   |                    |   |   |   |   |   |
| (Increase)  decrease in receivables                              |   | 2,145                    |   | (5,563                  | )      | 22,880 |   | (5,624 | ) |
| (Increase)  decrease in inventories                              |   | (2,074                   | )      | (5,058                  | )      | 736 |   | (5,776 | ) |
| (Increase)  decrease in prepaid expenses and other assets        |   | (7,250                   | )      | 486                     |   | (7,419 | ) | (1,770 | ) |
| Increase (decrease)  in accounts payable and accrued liabilities |   | 2,838                    |   | 3,437                   |   | (11,755 | ) | 10,530 |   |
|                                                             |   | (4,341                   | )      | (6,698                  | )      | (4,442 | ) | (2,640 | ) |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Net cash flow  provided by (used in) operating activities        |   | (1,600                   | )      | (3,598                  | )      | 12,432 |   | 7,822 |   |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Cash flows from  investing activities:                           |   |                     |   |                    |   |   |   |   |   |
| Capital  expenditures                                            |   | (4,151                   | )      | (3,139                  | )      | (19,907 | ) | (12,427 | ) |
| Acquisition of  Canadian operations, net of cash acquired        |   | (46,530                  | )      | —                  |   | (46,530 | ) | — |   |
| Proceeds from  sale of assets                                    |   | 16                       |   | 8                       |   | 36 |   | 6,492 |   |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Net cash used in  investing activities                           |   | (50,665                  | )      | (3,131                  | )      | (66,401 | ) | (5,935 | ) |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Cash flows from  financing activities:                           |   |                     |   |                    |   |   |   |   |   |
| Proceeds from  long-term debt                                    |   | 108,500                  |   | 20,000                  |   | 142,000 |   | 40,500 |   |
| Repayment of  long-term debt                                     |   | (53,500                  | )      | (13,000                 | )      | (84,000 | ) | (41,639 | ) |
| Debt issuance  costs                                             |   | (2,731                   | )      | (73                     | )      | (2,731 | ) | (336 | ) |
| Exercise of  options                                             |   | —                   |   | —                  |   | 18 |   | — |   |
| Net reissuance  (buy-back) of treasury stock                     |   | 84                       |   | (2                      | )      | 227 |   | (54 | ) |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Net cash  provided by (used in) financing activities             |   | 52,353                   |   | 6,925                   |   | 55,514 |   | (1,529 | ) |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Effect of  exchange rate changes on cash                         |   | (42                      | )      | —                  |   | (42 | ) | — |   |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Net increase in  cash and cash equivalents                       |   | 46                       |   | 196                     |   | 1,503 |   | 358 |   |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Cash and cash  equivalents at beginning of period                |   | 2,391                    |   | 1,518                   |   | 934 |   | 1,356 |   |
|                                                             |   |                     |   |                    |   |   |   |   |   |
| Cash and cash  equivalents at end of period                      |   | $                        | 2,437  |                    | $      | 1,714 |   | $ | 2,437 |   | $ | 1,714 |   |

 

The accompanying notesare an integral part of these financial statements.

**CONSOLIDATED STATEMENT OF CHANGES IN**

**STOCKHOLDERS’ EQUITY**

**(000s)**

** **
|                                     |   | **Shares of Common Stock** |   | **Shares of Treasury Stock** |   | **Common Stock** |   | **Additional Paid-In Capital** |   | **Retained Earnings** |   | **Treasury  Stock** |   | **Accumulated Other Comprehensive  Income** |   | **Total Stockholders’ Equity** |   |
|------------------------------------------|--------|----------------------------|--------|------------------------------|--------|------------------|--------|--------------------------------|--------|-----------------------|--------|---------------------|--------|---------------------------------------------|--------|-------------------------------------|--------|
|                                     |   |                       |   |                         |   |             |   |                           |   |                  |   |                |   |                                        |   |                                |   |
| Balance, December 31, 2000               |   | 8,561                      |   | (104                         | )      | $                | 86     |                           | $      | 42,471                |   | $                   | 19,679 |                                        | $      | (642                                | )      | $ | 0 |   | $ | 61,594 |   |
| Transition adjustment                    |   | **—**                 |   | **—**                   |   | **—**       |   | **—**                     |   | **—**            |   | **—**          |   | (1,230                                      | )      | (1,230                              | )      |
|                                     |   |                       |   |                         |   |             |   |                           |   |                  |   |                |   |                                        |   |                                |   |
| Net income                               |   | **—**                 |   | **—**                   |   | **—**       |   | **—**                     |   | 1,263                 |   | **—**          |   | —                                      |   | 1,263                               |   |
| Risk management activities               |   | **—**                 |   | **—**                   |   | **—**       |   | **—**                     |   | **—**            |   | **—**          |   | 4,687                                       |   | 4,687                               |   |
| Foreign currency translation adjustments |   | **—**                 |   | **—**                   |   | **—**       |   | **—**                     |   | **—**            |   | **—**          |   | (1,260                                      | )      | (1,260                              | )      |
| Comprehensive income                     |   |                       |   |                         |   |             |   |                           |   |                  |   |                |   |                                        |   |                                | $      | 4,690 |   |
|                                     |   |                       |   |                         |   |             |   |                           |   |                  |   |                |   |                                        |   |                                |   |
| Exercise of options                      |   | 3                          |   | —                       |   | 1                |   | 17                             |   | —                |   | —              |   | —                                      |   | 18                                  |   |
| Reissuance of treasury stock             |   | —                     |   | 27                           |   | —           |   | 61                             |   | —                |   | 166                 |   | —                                      |   | 227                                 |   |
|                                     |   |                       |   |                         |   |             |   |                           |   |                  |   |                |   |                                        |   |                                |   |
| Balance, September 30, 2001              |   | 8,564                      |   | (77                          | )      | $                | 87     |                           | $      | 42,549                |   | $                   | 20,942 |                                        | $      | (476                                | )      | $ | 2,197 |   | $ | 65,299 |   |
|                                          |        |                            |        |                              |        |                  |        |                                |        |                       |        |                     |        |                                             |        |                                     |        |  |  |  |  |  |  |  |  |  |  |  |

 

Theaccompanying notes are an integral part of these financial statements.

**NOTE 1.  GENERAL**

 

The consolidated financial statements include the accounts of MarkWestHydrocarbon, Inc. (“MarkWest”), and its wholly owned subsidiaries:

 
| •     MarkWest  Resources, Inc.           | •     Matrex, LLC                                |
|--------------------------------------------------------------------|---------------------------------------------------------------------------|
| •     MarkWest Michigan, Inc.             | •     MarkWest Resources Canada  Corp.           |
| •     Basin Pipeline, LLC                 | •     MarkWest Canadian Midstream  Services, Inc |
| •     West Shore Processing  Company, LLC |                                                                      |

 

Through consolidation, we have eliminated all significant intercompanyaccounts and transactions.

 

We have prepared the unaudited financial statements presented herein inaccordance with the instructions to Form 10-Q. The statements do not include all the information and note disclosuresrequired by generally 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, 2000,included in the Company’s Annual Report on Form 10-K, as filed with theSecurities and Exchange Commission.  Inthe opinion of management, we have made all necessary adjustments for a fairstatement of the results for the unaudited interim periods.  These are only normal recurring adjustments.

 

Webase the effective corporate tax rate for interim periods on the estimatedannual effective corporate tax rate, excluding certain nonrecurring or unusualevents.  The effective tax rate variesfrom statutory rates primarily due to the tax effect of the Canadianacquisition (discussed in Note 2), tax credits and Canadian resource allowance.

 

The functional currency of MarkWest is the dollar, except for itsCanadian operations that use the Canadian dollar.  Assets and liabilities of the Canadian operations are translatedat the spot rate in effect at the applicable reporting date, and the incomestatement accounts are translated at the average exchange rates in effectduring the applicable period.  Theresulting cumulative translation adjustment is recorded as a component ofaccumulated other comprehensive income.

 

We have reclassified certain prior-year amounts to conform to thecurrent year’s presentation.

 

**NOTE2.  ACQUISITION**

 

On August 10, 2001, MarkWest acquired for $50 million 100 percent ofthe voting shares of Leland Energy Canada, Ltd. and Watford Energy, Ltd. (“Leland/Watford”),two privately owned natural gas production companies active in central andsoutheast Alberta, Canada.   Themanagement of these companies has continued with MarkWest. The acquisitionincluded 26 Bcfe of proved reserves (95 percent natural gas), 106,000 netacres, and an inventory of 300 drillable locations.  The properties feature low-cost, shallow drilling for multiplepay horizons, with year-round drilling access. MarkWest is supplementing this acquisition with a midstream investmentin gathering and compression facilities in the area.

 

The purchase price was allocated as follows (in thousands):

 
| Acquisition costs:                  |   |   |   |
|-------------------------------------|--------|--------|--------|
| Long term debt  incurred            |   | $      | 49,005 |   |
| Direct  acquisition costs           |   | 1,301  |   |
|                                |   | 50,306 |   |
|                                |   |   |   |
| Current  liabilities assumed        |   | 7,413  |   |
| Deferred income  taxes              |   | 30,634 |   |
| Total  acquisition costs            |   | $      | 88,353 |   |
|                                |   |   |   |
| Allocation of  acquisition costs:   |   |   |   |
| Current assets                      |   | $      | 6,171  |   |
| Oil and gas  properties—proved |   | 46,886 |   |
| Undeveloped  properties             |   | 32,610 |   |
| Other facilities                    |   | 2,686  |   |
| Total                               |   | $      | 88,353 |   |

 

In addition to the $50 million acquisition cost identified above, werecorded a deferred income tax liability of $31 million to recognize thedifference between the historical tax basis of the Leland/Watford assets andthe acquisition costs recorded for book purposes.  The recorded book value of the oil and gas properties wasincreased to recognize this tax basis differential.

 

MarkWest has entered into employment contracts with certain executivesfrom Leland/Watford that provide for a minimum annual salary and incentivesbased on increases in reserve value, as defined, since the acquisition.  The executives’ entitlement to theseincentives vests over time through December 31, 2005, and are payable in cashor in kind by way of transferring to the executives a working interest in theacquired assets.

 

ProForma Results of Operations (Unaudited)

 

Thefollowing table reflects the unaudited pro forma consolidated results ofoperations for the nine months ended September 30, 2001 and 2000 as though theCanadian acquisitions had occurred on January 1st for the periodspresented.  These unaudited pro formaresults have been prepared for comparative purposes only and are not indicativeof future results.

 
|                          |   | **Nine Months Ended September 30,**       |    |
|-------------------------------|--------|-------------------------------------------|---------|
|                          |   | **2001**                                  |    | **2000** |   |
|                          |   | **(in thousands, except per share data)** |    |
|                          |   |                                      |    |   |   |
| Revenue                       |   | $                                         | 163,883 |   | $ | 147,432 |   |
| Net income                    |   | $                                         | 1,137   |   | $ | 7,979 |   |
| Basic net income per  share   |   | $                                         | 0.13    |   | $ | 0.94 |   |
| Diluted net income per  share |   | $                                         | 0.13    |   | $ | 0.94 |   |

 

Proforma net income included a bonus expense of $2.8 million and a gainon settlement of derivatives of $1.1 million for the nine months endedSeptember 30, 2001.  Proforma net incomeincluded a gain on sale of a partnership of $4.3 million for the nine monthsended September 30, 2000..

 

**NOTE 3.  LONG TERM DEBT**

 

Inconjunction with the Canadian acquisition (see Note 2), effective August 10,2001, we amended our credit agreement with various financial institutions.  The amended agreement provides for a $65million increase to our maximum borrowing amount, now $130 million.  The amended agreement is comprised of a $90million revolving line of credit and a term loan of $40 million.  The terms of the loans extend to August2005.  Actual borrowing limits may be alesser amount, depending upon trailing cash flow, as defined in theagreement.  All other aspects of theamended credit agreement, including rates, collateralization and restrictionsare similar to the prior agreement.

 

Effective October 12, 2001, we amended our credit agreement to replace$35 million of the existing $90 million revolving line of credit with aCanadian credit facility for the same amount. Our combined maximum borrowing amount remains at $130 million.  The term of this $35 million revolving lineof credit extends through October 2007. All other aspects of the amended credit agreement, including rates,collateralization and restrictions are similar to the prior agreement.

 

#### **NOTE 4.  RECENT ACCOUNTING PRONOUNCEMENTS**

#### ** **

#### **In June 1998, the Financial Accounting Standards Board(“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, *Accountingfor Derivative Instruments and Hedging Activities. *This statement, as amended by SFAS Nos. 137 and 138,is effective for fiscal years beginning after June 15, 2000.  SFAS No. 133 requires an entity to recognizeall derivatives as assets or liabilities in the balance sheet and measure thoseinstruments at fair value.  MarkWest hasadopted SFAS No. 133, as amended, on January 1, 2001.  See Note 7 Adoption of SFAS No. 133.**

 

In June 2001, the FASB issued SFAS No. 141, *Business Combinations*, whichaddresses financial accounting and reporting for business combinations.  SFAS No. 141 is effective for all businesscombinations initiated after June 30, 2001 and for all business combinationsaccounted for under the purchase method initiated before but completed afterJune 30, 2001.  All businesscombinations in the scope of this Statement are to be accounted for using onemethod – the purchase method.  Theadoption of SFAS No. 141 did not have a material impact on the Company’sfinancial position or results of operations.

 

In June 2001, the FASB issued SFAS No. 142, *Goodwill and Other Intangible**Assets*,which is effective for fiscal years beginning after December 15, 2001, andapplies to all goodwill and other intangibles recognized in the financialstatements at that date.  Under theprovisions of this statement, goodwill will not be amortized, but will betested for impairment on an annual basis. The adoption of SFAS No. 142 is not expected to have a material impacton the Company’s financial position or results of operations.

 

In July 2001, the FASB issued Statement of Financial AccountingStandards No. 143, *Accounting for Asset Retirement Obligations*(“SFAS 143”).  SFAS 143, is effectivefor fiscal years beginning after June 15, 2002 (January 1, 2003 forMarkWest), and establishes an accounting standard requiring the recording ofthe fair value of liabilities associated with the retirement of long-livedassets in the period in which they are incurred.  We are in the process of determining the future impact that theadoption of FAS 143 may have on our earnings and financial position.

#### ** **

In August 2001, the FASB issued SFAS No. 144, *Accounting for the Impairment orDisposal of Long-Lived Assets.* This statement requires the recognition of an impairment loss if thecarrying amount of a long-lived asset is not recoverable from its undiscountedcash flows and measures the impairment loss as the difference between thecarrying amount and fair value of the asset. The adoption of SFAS No. 144 is not expected to have a material impacton the Company’s financial position or results of operations.

 

#### **NOTE 5.   SEGMENT REPORTING**

# *** ***

Weclassify MarkWest’s operations into two reportable segments, as follows:

 

(1)   Gathering, Processing and Marketing(“GPM”)—provide compression, gathering, treatment, NGL extraction andfractionation services; also purchase and market natural gas and NGLs; and

(2)   Explorationand Production (“E & P”)—explore for and produce natural gas.

 

We evaluate the performance of our segments andallocate resources to them based on operating income. There are no intersegmentrevenues.  We conduct our business inthe United States and Canada.

 

Thetable below presents information about operating income for the reportedsegments for the second quarter of 2001 and 2000 and for the nine months endedSeptember 30, 2001 and 2000.  Operatingincome for each segment includes total revenues less operating expenses andexcludes depreciation, depletion and amortization, general and administrativeexpenses, interest expense, interest income and income taxes.  We have not reported asset information byreportable segment because we do not produce such information internally.

 
|                                               |   | **Gathering,  Processing and Marketing (000s)** |    | **Exploration and Production (000s)** |   | **Total (000s)** |   |
|----------------------------------------------------|--------|-------------------------------------------------|---------|---------------------------------------|--------|------------------|--------|
| **For the quarter ended September 30,  2001:**     |   |                                            |    |                                  |   |             |   |
| Revenues                                           |   | $                                               | 28,309  |                                  | $      | 4,084            |   | $ | 32,393 |   |
| Segment  operating income                          |   | $                                               | 2,930   |                                  | $      | 2,596            |   | $ | 5,526 |   |
|                                               |   |                                            |    |                                  |   |             |   |
| **For the quarter ended September 30,  2000:**     |   |                                            |    |                                  |   |             |   |
| Revenues                                           |   | $                                               | 55,845  |                                  | $      | 1,461            |   | $ | 57,306 |   |
| Segment  operating income                          |   | $                                               | 6,177   |                                  | $      | 424              |   | $ | 6,601 |   |
|                                               |   |                                            |    |                                  |   |             |   |
| **For the nine months ended September  30, 2001:** |   |                                            |    |                                  |   |             |   |
| Revenues                                           |   | $                                               | 142,368 |                                  | $      | 9,120            |   | $ | 151,488 |   |
| Segment  operating income                          |   | $                                               | 10,808  |                                  | $      | 6,141            |   | $ | 16,949 |   |
|                                               |   |                                            |    |                                  |   |             |   |
| **For the nine months ended September  30, 2000:** |   |                                            |    |                                  |   |             |   |
| Revenues                                           |   | $                                               | 139,329 |                                  | $      | 3,279            |   | $ | 142,608 |   |
| Segment  operating income                          |   | $                                               | 19,721  |                                  | $      | 1,000            |   | $ | 20,721 |   |

 

Following is a reconciliation of total segment operating income tototal consolidated income before taxes (000s):

 
|                                 |   | **For the quarter ended**

**September 30,** |   | **For the nine months ended**

**September 30,** |   |
|--------------------------------------|--------|----------------------------------------------|--------|--------------------------------------------------|--------|
|                                 |   | **2001**                                     |   | **2000**                                         |   | **2001** |   | **2000** |   |
| Total segment operating  income      |   | $                                            | 5,526  |                                             | $      | 6,601 |   | $ | 16,949 |   | $ | 20,721 |   |
| General and  administrative expenses |   | (1,906                                       | )      | (2,173                                           | )      | (6,189 | ) | (6,031 | ) |
| Depreciation and  amortization       |   | (3,295                                       | )      | (1,427                                           | )      | (6,700 | ) | (4,323 | ) |
| Interest income                      |   | 32                                           |   | 24                                               |   | 114 |   | 77 |   |
| Interest  expense                    |   | (974                                         | )      | (820                                             | )      | (2,234 | ) | (2,222 | ) |
| Gain  on sale of assets              |   | —                                       |   | —                                           |   | — |   | 1,000 |   |
| Other  income (expense)              |   | (4                                           | )      | (81                                              | )      | (253 | ) | 22 |   |
| Income  (loss) before taxes          |   | $                                            | (621   | )                                                | $      | 2,124 |   | $ | 1,687 |   | $ | 9,244 |   |

** **

**NOTE6.  CONTINGENCY**

 

In February 2001, threecomplaints were filed against MarkWest Hydrocarbon, Inc., in the Circuit Courtof Wayne County, West Virginia, by Columbia Gas Transmission Corporation andColumbia Natural Resources, Inc.; Equitable Production Company and EquitableEnergy LLC; and Cobra Petroleum Company et al. These complaints each allege breach of contract and seek various formsof relief (including injunctive relief) and damages.  Losses, if any, with regard to these complaints areundeterminable.  In July 2001, MarkWestfiled an action in the Denver District Court, Denver, Colorado, againstColumbia Gas Transmission Corporation and Columbia Natural Resources, Inc.;Equitable Production Company and Equitable Energy, LLC; and Cobra PetroleumProduction Company et al, to compel arbitration on these matters in accordancewith provisions in existing contracts. In August 2001, the Circuit Court of Wayne County, West Virginia, hasgranted the plaintiff’s motion for a temporary mandatory injunction requiringMarkWest to return natural gas to producers in accordance with contractualcommitments.  The ruling has no impact,as MarkWest has continually returned natural gas in accordance with itsagreement.  MarkWest has requestedreconsideration of certain aspects of the ruling.  In addition, a trial date has been scheduled for February2002.  MarkWest is continuing settlementnegotiations with various parties.

 

## **NOTE 7.  ADOPTION OF SFAS NO. 133**

 

MarkWest adopted SFAS No. 133, *Accounting for Derivative Instruments and HedgingActivities*, as amended, on January 1, 2001.  In accordance with the transition provisionsof SFAS 133, we recorded on that date a net-of-tax cumulative effectadjustment of approximately $1.2 million loss to other comprehensive income torecognize at fair value all derivatives that are designated as cash-flowhedging instruments.

 

SFAS 133 establishes accounting and reporting standards requiringderivative instruments to be recorded in the balance sheet as either an assetor liability measured at fair value. Changes in the derivative instruments’ fair value are recognized inearnings unless specific hedge accounting criteria are met.

 

SFAS 133 allows hedge accounting for fair-value and cash-flowhedges.  A fair-value hedge applies to arecognized asset or liability or an unrecognized firm commitment.  A cash-flow hedge applies to a forecastedtransaction or a variable cash flow of a recognized asset or liability.  SFAS 133 provides that the gain or loss on aderivative instrument designated and qualifying as a fair-value hedginginstrument as well as the offsetting loss or gain on the hedged item berecognized currently in earnings in the same accounting period.  SFAS 133 provides that the effective portionof the gain or loss on a derivative instrument designated and qualifying as acash-flow hedging instrument be reported as a component of other comprehensiveincome and be reclassified into earnings in the same period during which thehedged forecasted transaction affects earnings. (The remaining gain or loss onthe derivative instrument, if any, must be recognized currently in earnings.)  Effectiveness is evaluated by the derivativeinstrument’s ability to generate offsetting changes in fair value or cash flowsto the hedged item.  We formallydocument, designate and assess the effectiveness of transactions receivinghedge accounting treatment.

 

In our gathering, processing and marketing segment, we enter intofixed-price contracts for the sale of NGLs and fixed-price purchases for thepurchase of natural gas and NGLs.  AtJanuary 1, 2001, we recorded a risk management asset of approximately $2.1 millionin the balance sheet with an offsetting amount recorded, less a deferred taxliability of approximately $0.7 million, in other comprehensiveincome—approximately $1.3 million gain. At September 30, 2001, the risk management liability was $2.2 million,less $0.8 million deferred tax recovery, resulting in a $1.4 million loss inother comprehensive income.  We alsorecorded a $0.4 million risk management liability and a corresponding riskmanagement asset to reflect our fair value hedges.

In our exploration and production segment, MarkWest enters intofixed-price contracts for the sale of natural gas.  At January 1, 2001, we recorded a risk management liability ofapproximately $3.9 million in the balance sheet with an offsetting amountrecorded, less a deferred tax recovery of approximately $1.4 million, in othercomprehensive income—approximately $2.5 million loss.  At September 30, 2001, the risk management asset was $8.0million, less $2.8 million deferred tax liability, resulting in a $5.2 milliongain in other comprehensive income.

 

Duringthe second quarter of 2001, we have entered into three year contracts to fixinterest rates on $10 million of our debt at 5.28% compared to a floating LIBOR(in both cases, plus an applicable margin). At September 30, 2001, we recorded a risk management liability ofapproximately $0.4 million in the balance sheet with an offsetting amountrecorded, less a deferred tax recovery of approximately $0.1 million, resultingin a $0.3 million loss in other comprehensive income.

 

Together,at January 1, 2001, these amounts comprise the above net-of-tax cumulativeeffect adjustment of approximately $1.2 million loss to other comprehensiveincome.  At September 30, 2001, with alltransactions considered, there is a $3.5 million gain to accumulated othercomprehensive income.

 

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

 

ThisManagement’s Discussion and Analysis contains statements which, to the extentthat they are not recitations of historical fact, constitute “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of 1933(“Section 27A”) and Section 21E of the Securities and Exchange Act of 1934 asamended (“Section 21E”).  This includes,among other things, statements with respect to the outcome of the pendinglitigation matters and contract negotiations. All forward-looking statements involve risks and uncertainties.  We intend that all forward-lookingstatements in this document are subject to the safe harbor protection providedby Sections 27A and 21E.  Factors thatmost typically impact MarkWest’s operating results and financial conditioninclude:

•      changes in general economic conditions inregions where our products are located

•      the availability and prices of NGL andcompeting commodities

•      the availability and prices of raw naturalgas supply

•      our ability to negotiate favorablemarketing agreements

•      the risks that third party or MarkWest’snatural gas exploration and production activities will not occur or besuccessful

•      our dependence on certain significantcustomers, producers, gatherers, treaters and transporters of natural gas

•      competition from other NGL processors,including major energy companies

•      our ability to identify and consummategrass-roots projects or acquisitions complementary to our business

•      winter weather conditions

•      intermediate or final decisions in thepending litigation and the relative positions of the parties in the negotiationof new processing agreements

•      changes in foreign economics, currency,and laws and regulations in Canada where MarkWest has made direct investments

•      our ability to integrate the recentCanadian acquisition to operate an exploration and production company inCanada, and to manage the Company as a more exploration and production focusedenterprise.

 

Inaddition, there are certain factors that impact MarkWest’s exploration andproduction segment.  These includeuncertainties inherent in estimating quantities of proven oil and gas reserves,projecting rates of production and timing of development expenditures.  The drilling of wells can involvesignificant risks including those related to timing, success rates and costoverruns.  Rig availability, complexgeology and other factors can affect these risks.  Future gas and oil prices also could affect results of operationsand cash flows.

 

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

 

**Operating data**
|                                        |   | **Three Months Ended September 30,** |   | **Nine Months Ended September 30,** |   |
|---------------------------------------------|--------|--------------------------------------|--------|-------------------------------------|--------|
|                                        |   | **2001**                             |   | **2000**                            |   | **% Change** |   | **2001** |   | **2000** |   | **% Change** |   |
| Gathering,  processing and marketing        |   |                                 |   |                                |   |   |   |   |   |   |   |   |   |
| Appalachia:                                 |   |                                 |   |                                |   |   |   |   |   |   |   |   |   |
| NGL  production—Siloam plant (gallons) |   | 38,900,000                           |   | 41,500,000                          |   | (6 | )% | 111,000,000 |   | 115,300,000 |   | (4% | ) |
| NGL sales—Siloam  plant (gallons)      |   | 35,200,000                           |   | 39,800,000                          |   | (12 | )% | 106,200,000 |   | 109,500,000 |   | (3% | ) |
| Processing  margin per gallon:              |   |                                 |   |                                |   |   |   |   |   |   |   |   |   |
| Average NGL  sales price                    |   | $                                    | 0.46   |                                | $      | 0.63 |   | (27 | )% | $ | 0.59 |   | $ | 0.59 |   | — |   |
| Average natural  gas cost                   |   | 0.36                                 |   | 0.43                                |   | (16 | )% | 0.45 |   | 0.38 |   | 18 | % |
| Processing  margin per gallon               |   | $                                    | 0.10   |                                | $      | 0.20 |   | (50 | )% | $ | 0.14 |   | $ | 0.21 |   | (33% | ) |
|                                        |   |                                 |   |                                |   |   |   |   |   |   |   |   |   |
| Michigan:                                   |   |                                 |   |                                |   |   |   |   |   |   |   |   |   |
| Pipeline  throughput (Mcfd)                 |   | 10,200                               |   | 9,600                               |   | 6 | % | 8,700 |   | 11,800 |   | (26% | ) |
| NGL sales  (gallons)                        |   | 2,400,000                            |   | 2,000,000                           |   | 20 | % | 5,900,000 |   | 7,300,000 |   | (19% | ) |
|                                        |   |                                 |   |                                |   |   |   |   |   |   |   |   |   |
| Exploration and  production                 |   |                                 |   |                                |   |   |   |   |   |   |   |   |   |
| Natural gas  produced (Mcfed)               |   | 16,700                               |   | 4,000                               |   | 318 | % | 10,200 |   | 3,500 |   | 191 | % |
| Average price  per Mcfe                     |   | $                                    | 2.66   |                                | $      | 2.51 |   | 6 | % | $ | 3.38 |   | $ | 2.34 |   | 44 | % |
|                                             |        |                                      |        |                                     |        |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

## **Three Months EndedSeptember 30, 2001, Compared to the Three Months Ended September 30, 2000**

**(in 000s)**

** **
|                                  |   | **2001** |   | **2000** |   |   | **$ Change** |   |
|---------------------------------------|--------|----------|--------|----------|--------|--------|--------------|--------|
| Revenues                              |   | $        | 32,393 |     | $      | 57,306 |         | $      | (24,913) |   |
| Income from  operations               |   | $        | 325    |     | $      | 3,001  |         | $      | (2,676 | ) |
|                                  |   |     |   |     |   |   |         |
| Income (loss)  before income taxes    |   | $        | (621   | )        | $      | 2,124  |         | $      | (2,746 | ) |
| Provision  (benefit) for income taxes |   | (427     | )      | 799      |   | (1,226 | )            |
| Net income                            |   | $        | (194   | )        | $      | 1,325  |         | $      | (1,520 | ) |
|                                  |   |     |   |     |   |   |         |
| Basic earnings  (loss) per share      |   | $        | (0.02  | )        | $      | 0.16   |         | $      | (0.18 | ) |

 

Thestrongest demand for propane, and consequently the highest volumes of andmargins for propane sales, generally occur in the winter heating season.  Therefore, a substantial portion of our netincome is recognized in the first and fourth quarters.  This seasonality occurs in the GPM segmentof our business.

 

Forthe quarter ended September 30, 2001, we report a net loss of $0.2 million, or$0.02 per share, compared to net income, of $1.3 million, or $0.16 per share,for the same period last year.  Earningsbefore interest, taxes and depreciation, depletion and amortization (“EBITDA”)was $3.6 million versus $4.3 million in the third quarter of 2001 and 2000,respectively.

 

TheGPM segment’s cash operating income was down $3.2 million compared to2000.  MarkWest’s Appalachian operationsexperienced a lower spread between the price of the NGLs versus the cost of thenatural gas than in the previous year, when the margin was significantly aboveaverage.  The margin was $0.10 pergallon versus $0.20 per gallon, or $2.7 million less margin in third quarter2001.  Sales volumes were 26.5 milliongallons versus 29.9 million gallons, down 11 percent from third quarter 2000 to2001.  This unfavorable volume variancetranslates to $0.7 million less margin in third quarter 2001.  The decline was due to delays of additionalthird-party compression facilities and gathering pipeline relocations.  Natural gas marketing revenues are $19.2million less than last year.  Thisdecrease had a negligible affect on overall results of the GPM segment.  Natural gas marketing activities are lowmargin transactions done in support of our processing business.  The E&P segment’s cash operating incomewas $2.2 million ahead of last year due to the Canadian acquisition and in theRocky Mountain E&P business segment, higher volume and prices as well asthe San Juan property acquired earlier this year, improved 2001 results.  Depreciation, depletion and amortizationwere up $1.9 million due to the Canadian acquisition and other company growth.

 

**Nine Months Ended September 30, 2001, Compared to the NineMonths Ended September 30, 2000 (in 000s)**

** **
|                                                        |   | **2001** |    | **2000** |   |    | **$ Change** |   |
|-------------------------------------------------------------|--------|----------|---------|----------|--------|---------|--------------|--------|
| Revenues                                                    |   | $        | 151,488 |     | $      | 142,608 |         | $      | 8,880 |   |
| Income from  operations                                     |   | $        | 4,060   |     | $      | 10,367  |         | $      | (6,307 | ) |
|                                                        |   |     |    |     |   |    |         |
| Income before  income taxes                                 |   | $        | 1,687   |     | $      | 9,244   |         | $      | (7,557 | ) |
| Provision for  income taxes                                 |   | 424      |    | 3,558    |   | 3,134   |         |
| Net income                                                  |   | $        | 1,263   |     | $      | 5,686   |         | $      | (4,423 | ) |
| Net income,  excluding gain on sale of assets               |   | $        | 1,263   |     | $      | 5,066   |         | $      | (3,803 | ) |
|                                                        |   |     |    |     |   |    |         |
| Basic earnings  per share                                   |   | $        | 0.15    |     | $      | 0.67    |         | $      | (0.52 | ) |
| Basic earnings  per share, excluding gain on sale of assets |   | $        | 0.15    |     | $      | 0.60    |         | $      | (0.45 | ) |

 

# ***For thenine months ended September 30, 2001, we report net income of $1.3 million, or$0.15 per share, compared to net income, excluding gain on sale, of $5.1million, or $0.60 per share, for the same period last year.  Earnings before interest, taxes anddepreciation, depletion and amortization (“EBITDA”) was $10.5 million versus$14.7 million in 2001 and 2000, respectively.***

 

TheGPM segment’s cash operating income was down $8.9 million compared to2000.  MarkWest’s Appalachian operationsexperienced a lower spread between the price of the NGLs versus the cost of thenatural gas than in the previous year when the margin was significantly aboveaverage.  The margin was $0.14 versus$0.21, a difference of $0.07 per gallon, or $5.6 million less margin in2001.  The $0.14 margin per gallonearned in 2001 is slightly below the ten year average of $0.16 margin pergallon.  Natural gas marketing revenuesare $0.2 million less than last year. This decrease had a negligible affect on overall results of the GPMsegment.  Natural gas marketingactivities are low margin transactions done is support of our processingbusiness.    The E&P segment was$5.1 million ahead of last year due to the Canadian acquisition and in theRocky Mountain E&P business unit, higher volume and prices, as well as theadditional San Juan properties acquired earlier this year improved 2001results.  Operating expenses as well asthe general and administrative costs were higher in 2001 than the same periodlast year primarily due to the Canadian acquisition and increases related tothe capital expansions and acquisitions since last year.  Depreciation, depletion and amortizationwere up $2.4 million due to the Canadian acquisition and other company growth.

 

# ***Gathering, Processing and Marketing  (GPM)***

# *** ***

Weare paid for our processing in Appalachia through sales of liquids extractedand fees for units of throughput.  Alarge portion, about 65 percent, of our processing services for gas producersin Appalachia involves extracting NGLs from inlet gas streams and replacing theequivalent heat content with dry natural gas purchased in the spot or forwardmarket.   Consequently, this segment ofour business depends on a positive spread between the NGL prices and the costof the replacement natural gas (“processing margin”).

 

Thecash operating income for the GPM segment was $2.9 million for the thirdquarter and $10.8 million year to date for 2001.  This compares with $6.2 million and $19.7 million respectivelyfor the year 2000.  The expansion of theKenova plant is complete, but disappointing throughput in the Appalachiansystem was largely due to lack of adequate compressor capabilities of thirdparties supplying natural gas from the wellhead to our processing plants andgathering pipeline relocations.

 

A lower frac spread between the price of the NGL’s verses the cost ofthe natural gas negatively impacted our gross margin in Appalachia.  2000 margins were significantly aboveaverage.  The unfavorable price variancein the third quarter was $2.6 million. Volumes sold at our Siloam fractionator during the third quarter are 11percent lower than the same quarter last year, but on a year-to-date basis; thevolume variance is negligible, less than 3 percent.  The volumes were lower for the reason stated above.

 

Earlier in the year2001, there was a dramatic decline in the prices of NGLs that triggered a writedown of inventory value at our Appalachia propane terminals negativelyimpacting the Appalachian gross margins in 2001.

 

In western Michigan,volumes were up modestly, but should trend up in the fourth quarter and evenmore in the first quarter of 2002.  Asmany as six additional, largely third party, wells are expected to be connectedto the system by year-end which should double the throughput rate to 20,000Mcfd as we enter the new year.

 

### **Explorationand Production (E & P)**

 

Cash operating income for MarkWest’s E&P businesses increased to$2.6 million for the third quarter and $6.1 million year-to-date 2001.  This compares favorably with the $0.4million for the third quarter of 2000 and $1.0 million for year-to-date2000.  High natural gas prices,acquisitions, new projects in eastern Michigan and benefits of our prior yearcapital investments have all favorably impacted the operating income for thissegment.

 

This large increase is due to a 77 percent increase in productionvolume in the San Juan basin properties and production from the $50 millionacquisition of the Canadian units included for the first time.  Canadian production included only the lasttwo months of the quarter.  Both unitsare in significant exploitation modes with a multi-year inventory of drillablelocations.  The success of the thirdquarter exploration program added between 5 and 6 Bcfe of additional reserves.   Approximately 20 wells were awaitingconnection at quarter’s end and should be flowing late fourth quarter and earlyfirst quarter 2002.

 

In eastern Michigan, the Au Gres project continues to grow with theaddition of a second well and plans for a third recompletion are nearlycomplete.

* *

***Revenues and Expenses***

 

*Revenues*

Revenues increased from$142.6 million to $151.5 million year-to-date 2000 compared to 2001.  During the third quarter, the revenues are$24.9 million lower in 2001 compared to 2000.

 

Gas marketing activitiesare low margin transactions done in support of our processing business.  The volume and gross margins have decreasedthis year.   The 2001 year-to-date gasmarketing revenues are $0.2 million behind last year at the same time, and thirdquarter 2001 revenues are $19.2 million behind third quarter 2000revenues.  However, this low marginactivity impacted operating profit only negligibly.

 

Our GPM segment,excluding gas marketing activities previously mentioned, had revenues of $21.4million and $29.7 million for the third quarter 2001 and 2000; however,year-to-date 2001 revenues are still ahead of prior year by $3.2 million.  The quarterly decrease is predominately inthe Appalachian NGL sales price.  Theprices decreased from $0.63 per gallon to $0.46 per gallon in 2001.  NGL sales volumes were also down for thethird quarter 2001 compared to 2000 by 4.6 million gallons.  These price and volume decreases translateto $9.1 million less revenue for the third quarter 2001.

 

Our E&P segmentcontributed an additional $5.8 million to year-to-date revenues, with $2.6million of that in the third quarter of 2001. The additional revenue is the result of the AuGres project coming online in July 2000, high natural gas prices, and the benefits of last year’scapital expenditures.  We also hadhigher volumes due to an acquisition earlier this year and the addition ofCanadian production beginning in August 2001.

 

*Cost of Sales*

Cost of sales increasedfrom $109.6 million to $120.6 million year-to-date 2000 compared to 2001.  During the third quarter, cost of sales are$24.4 million lower in 2001 compared to 2000.

 

Gas marketing cost ofsales, like revenues, are down $19.4 million in third quarter 2001 compared to2000, and are down $0.9 million year-to-date. This low margin activity impacted operating profit only negligibly.

 

Our GPM segment cost of sales are $12.3 million higher year-to-date2001 compared to 2000.  The predominantcause of this increase is related to the feedstock cost increase.  In 2000, the cost per gallon was $0.38versus a cost of $0.45 for 2001.

 

*Operating Expenses*

Operating expensesincreased $1.7 million or 14% for the nine months ended September 30, 2001compared to the same period last year. The third quarter’s operating expenses increased $0.6 or 14% from 2000to 2001.  Much of the increased costsyear-to-date relate to the acquisitions and expansions from 2000 being on linefor all of 2001 as opposed to only part of 2000, as well as higher fuel costsin 2001.  The third quarter’s increasedcosts are almost entirely attributable to the Canadian acquisition

 

*General and Administrative Expenses*

General andadministrative expenses were $6.2 and $6.0 million year-to-date 2001 and 2000,respectively.  General andadministrative expenses were $1.9 and $2.2 for the third quarter 2001 and 2000,respectively.  The third quarterdecrease is due to capitalization of overhead costs for construction projectsand general cost cutting, partially offset by the new Canadian unit and legal expenses.

 

*Depreciation, Depletion and Amortization*

Depreciation, depletionand amortization increased significantly year-to-date ($2.4 million) and forthe third quarter ($1.9 million) 2001 compared to 2000.  The increase is primarily related to oil andgas properties of $82.1 million acquired in the Canadian acquisition.  A portion of the additional depletion isbeing recovered with a deferred tax benefit related to the step-up in basis ofCanadian assets.  In addition, therewere significant capital expenditures made in 2000 and early in 2001.

 

*Other income and expense*

During the secondquarter 2000, we sold an asset for a $1.0 million pre-tax gain.

 

### **Liquidityand Capital Resources**

 

MarkWest’ssources of liquidity and capital resources historically have been internal cashflow and our revolving line of credit. In the first quarter of 2000, we supplemented these sources withproceeds from the sale of our corporate office building.  In the second quarter of 2000, we increasedour line of credit by $15 million to $65 million.  In the third quarter of 2001, we increased our credit linefurther to $130 million.

 

Thefollowing summary table reflects our comparative cash flows for the nine monthsended September 30, 2001 and 2000 (in thousands):

 
|                                                                                |   | **For the nine months ended September 30,** |    |
|-------------------------------------------------------------------------------------|--------|---------------------------------------------|---------|
|                                                                                |   | **2001**                                    |    | **2000** |   |
|                                                                                |   |                                        |    |   |   |
| Net cash provided by operating  activities before change in working capital         |   | $                                           | 7,990   |   | $ | 10,462 |   |
| Net cash provided by (used in) operating  activities from change in working capital |   | $                                           | 4,442   |   | $ | (2,640 | ) |
| Net cash provided by (used in) investing  activities                                |   | $                                           | (66,401 | ) | $ | (5,935 | ) |
| Net cash used in financing activities                                               |   | $                                           | 55,514  |   | $ | (1,529 | ) |

 

###### *CapitalInvestment Program*

 

MarkWest forecasts abaseline capital budget of $28 million in 2001 in addition to our $50million acquisition.  In our gathering,processing and marketing segment the 2001 capital budget includes $8 millionfor completion of Appalachia’s Phase II expansion and up to $5 million for newinfrastructure to serve our recently acquired Canadian properties.  The 2001 capital budget also includes $13million for our exploration and production segment—$5 million for theacquisition of San Juan Basin properties in January 2001; $2 million for infilldrilling in the San Juan Basin; $2 million in Michigan; and $4 million for ournew Canadian properties.  In addition,MarkWest spent $50 million for the Canadian acquisition.

 

*Financing Facilities*

 

Financingactivities consist primarily of net borrowings under MarkWest’s creditfacilities.  At September 30, 2001, wehad $130 million of available credit, of which we had utilized $98.6million.  Depending on the timing andamount of our capital projects, we may have to seek additional sources ofcapital.  While we believe that we willbe able to secure additional financing on acceptable terms, if required, wehave no assurance that we will be able to do so.

 

## **Commodity Price RiskManagement**

 

MarkWest’sprimary risk management objective is to reduce volatility in our cashflows.  Our hedging approach uses astatistical method that analyzes momentum and average pricing over time andvarious fundamental data, such as industry inventories, industry production,demand and weather.  Hedging levelsincrease with capital commitments and debt levels and when above-average marginsexist.  We maintain a committee,including members of senior management, which oversees all hedging activity.

 

We achieve our goalsutilizing a combination of fixed-price forward contracts and fixed-for-floatprice swaps on the over-the–counter (“OTC”) market.  New York Mercantile Exchange(“NYMEX”)-traded futures are authorized for use, but only occasionallyused.  Swaps and futures allow us toprotect margins, because gains or losses in the physical market are generallyoffset by corresponding losses or gains in the value of financial instruments.

 

We enter OTC swaps withcounterparties that are primarily of other energy companies.  We conduct a standard credit review and haveagreements with such parties that contain collateral requirements.  We use standardized swap agreements thatallow for offset of positive and negative exposures.  Net credit exposure is marked to market daily.  We are subject to margin deposit requirementsunder OTC agreements (and NYMEX positions).

 

The use of financial instruments may expose MarkWestto the risk of financial loss in certain circumstances, including instanceswhen (a) sales volumes are less than expected, requiring market purchases tomeet commitments; or (b) our OTC counterparties fail to purchase or deliver thecontracted quantities of natural gas, NGLs, or crude oil, or otherwise fail toperform.  To the extent that we engagein hedging activities, we may be prevented from realizing the benefits offavorable price changes in the physical market.  However, we are similarly insulated against decreases in suchprices.

 

MarkWesthedges our basis risk for natural gas, but we are generally unable to do so forNGLs.  Our basis risk stems from thegeographic price differentials between our sales locations and hedging contractdelivery locations.  Basis risk is therisk that an adverse change in the hedging market will not be completely offsetby an equal and opposite change in the price of the physical commodity beinghedged.

 

Inour gathering, processing and marketing segment, we hedge Appalachia processingmargins by using a combination of methods. We protect margins by purchasing natural gas priced on predetermined Btudifferentials to propane or crude, by simultaneously selling propane or crudeoil and purchasing natural gas, and by using swaps.  Crude oil is highly correlated with certain NGL products.  All projected margins on open positionsassume the basis differentials between crude oil, and NGLs are consistent withhistorical averages.  As of September30, 2001, we have hedged NGL volumes and associated projected margin per NGLgallon, as follows:

 
|                              |   | **Hedged Processing Margin** |   |
|-----------------------------------|--------|------------------------------|--------|
|                              |   |                         |   |   |   |   |   |   |   |   |   |
|                              |   | **4th Qtr**                  |   | **1st Qtr** |   | **2nd Qtr** |   | **3rd Qtr** |   | **Total** |   |
|                              |   | **2001**                     |   | **2002** |   | **2002** |   | **2002** |   | **2002** |   |
| Using Crude Oil                   |   |                         |   |   |   |   |   |   |   |   |   |
| NGL gallons                       |   | 11,250,000                   |   | 6,420,000 |   | 2,520,000 |   | 1,680,000 |   | 10,620,000 |   |
| NGL processing margin ($/gallon)  |   | $                            | 0.26   |   | $ | 0.25 |   | $ | 0.20 |   | $ | 0.18 |   | $ | 0.23 |   |
|                              |   |                         |   |   |   |   |   |   |   |   |   |
| Using  Propane                    |   |                         |   |   |   |   |   |   |   |   |   |
| Propane  gallons                  |   | 17,470,000                   |   | 18,600,000 |   | 2,520,000 |   | — |   | 21,120,000 |   |
| NGL  processing margin ($/gallon) |   | $                            | 0.19   |   | $ | 0.19 |   | $ | 0.16 |   | — |   | $ | 0.19 |   |
|                              |   |                         |   |   |   |   |   |   |   |   |   |
| Total                             |   |                         |   |   |   |   |   |   |   |   |   |
| NGL gallons                       |   | 28,720,000                   |   | 25,020,000 |   | 5,040,000 |   | 1,680,000 |   | 31,740,000 |   |
| NGL processing margin  ($/gallon) |   | $                            | 0.22   |   | $ | 0.21 |   | $ | 0.18 |   | $ | 0.18 |   | $ | 0.20 |   |
|                                   |        |                              |        |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Wehave also hedged natural gas liquid sales as follows:

 
|        |     |        |   | **Hedged Sales Price for NGLs** |   |        |   |
|-------------|----------|-------------|--------|---------------------------------|--------|-------------|--------|
|        |     | **2nd Qtr** |   | **3rd Qtr**                     |   | **4th Qtr** |   | **Total** |   |
|        |     | **2002**    |   | **2002**                        |   | **2002**    |   | **2002** |   |
|        |     |        |   |                            |   |        |   |   |   |
| NGL gallons |     | 2,500,000   |   | 5,000,000                       |   | 1,700,000   |   | 9,200,000 |   |
|        |     |        |   |                            |   |        |   |   |   |
|        | $/gallon |        | $      | 0.47                            |   | $           | 0.47   |   | $ | 0.47 |   | $ | 0.47 |   |
|             |          |             |        |                                 |        |             |        |  |  |  |  |  |  |  |

 

Subsequent to September30, 2001, as of October 30, 2001, we have also hedged more natural gas liquidsales as follows:

 
|        |   |                   |   | **Hedged Sales Price for NGLs** |   |             |   |
|-------------|--------|------------------------|--------|---------------------------------|--------|------------------|--------|
|        |   | **2nd Qtr  2002** |   | **3rd Qtr 2002**                |   | **4th Qtr 2002** |   | **Total 2002** |   |
|        |   |                   |   |                            |   |             |   |   |   |
| NGL gallons |   | 3,800,000              |   | 12,500,000                      |   | 5,100,000        |   | 21,400,000 |   |
|        |   |                   |   |                            |   |             |   |   |   |
| $/gallon    |   | $                      | 0.47   |                            | $      | 0.47             |   | $ | 0.47 |   | $ | 0.47 |   |
|             |        |                        |        |                                 |        |                  |        |  |  |  |  |  |  |

 

For certain Appalachianatural gas liquid purchases, as of September 30, 2001, we have hedged 0.7million and 1.1 million gallons at $0.54 per gallon for fourth quarter2001 and first quarter 2002, respectively. For certain Appalachia natural gas sales, as of September 30, 2001, wehave hedged 206,000 and 444,000 MMBtu at $5.19 per MMBtu for 2001 and 2002,respectively.

 

Inaddition to these risk management tools, MarkWest utilizes our NGL storagefacilities and contracts for third-party storage to build product inventoriesduring historically lower-priced periods for resale during higher-priced periods.  We also have contracts to purchase certainquantities of our natural gas feedstock in advance of physical needs.

 

Inour exploration and production segment, we hedge our exposure to changes inmarket prices for our natural gas production. As of September 30, 2001, we had hedged natural gas volumes and pricesas follows:

 
|                          |   |        |   |        |   | **Hedged Natural Gas Sales** |   |        |   |        |   |      |   |
|-------------------------------|--------|-------------|--------|-------------|--------|------------------------------|--------|-------------|--------|-------------|--------|-----------|--------|
|                          |   | **4th Qtr** |   | **1st Qtr** |   | **2nd Qtr**                  |   | **3rd Qtr** |   | **4th Qtr** |   | **Total** |   |   |   |   |   |
|                          |   | **2001**    |   | **2002**    |   | **2002**                     |   | **2002**    |   | **2002**    |   | **2002**  |   | **2003** |   | **2004** |   |
|                          |   |        |   |        |   |                         |   |        |   |        |   |      |   |   |   |   |   |
| MMBtu                         |   | 1,340,000   |   | 1,260,000   |   | 1,220,000                    |   | 1,280,000   |   | 1,250,000   |   | 5,010,000 |   | 3,700,000 |   | 1,820,000 |   |
| $ /MMBtu                      |   | $           | 3.25   |        | $      | 3.38                         |   | $           | 3.14   |        | $      | 3.13      |   | $ | 3.15 |   | $ | 3.20 |   | $ | 3.25 |   | $ | 3.09 |   |
|                          |   |        |   |        |   |                         |   |        |   |        |   |      |   |   |   |   |   |
| Henry Hub  Equivalent $/MMBtu |   | $           | 3.66   |        | $      | 3.82                         |   | $           | 3.59   |        | $      | 3.58      |   | $ | 3.60 |   | $ | 3.64 |   | $ | 3.68 |   | $ | 3.57 |   |

 

As a result of the Canadian E&P acquisition, we are transitioning ourhedging strategy to recognize the natural hedge between our E&P productionand our natural gas purchase requirements in our Appalachian GPM business.  Going forward, we anticipate hedging NGLsales and net gas sales (i.e. the excess of production over purchases).

 

MarkWest’s hedging strategy benefited our after-tax earnings compared tothe situation of not hedging.  In thegathering, processing and marketing segment, without hedging, net income wouldhave been lower by $0 million and $1.2 million for the three and nine monthsended September 30, 2001.  Forcomparison, net income would have been higher by $0.7 million and $1.6 millionfor the three and nine months ended September 30, 2000.  This impact considers only hedges ofAppalachia processing margin and does not reflect other decisions madeconcerning when to buy natural gas or store NGL production for sale in latermonths.  In the exploration andproduction segment, without hedging, net income would have been lower by $0.4million and higher by $0.4 million for the three and nine months ended September30, 2001.  For comparison, net incomewould have been higher by $0.2 million and $0.3 million for the three and ninemonths ended September 30, 2000.

 

We enter into speculativetransactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior toexecuting such transactions. Speculative transactions are marked to market at the end of eachaccounting period, and any gain or loss is recognized in income for thatperiod.  There were no such speculativeactivities for the quarters ended September 30, 2001 and 2000.

 

**Outlook**

* *

In the Appalachian GPM segment, the expansion of the Kenova gas plantis complete and on line.  This completesthe Phase II expansion program which also involved the building of a new plantnear the existing Kenova plant.  NGLproduction is ramping up to 170 million gallons in 2002 compared to theanticipated 145 million gallons in 2001 from these new and expandedfacilities.  Planning for other newprojects is also underway.

 

In the Michigan GPM segment, the two new discoveries made with industrypartners earlier this year and a newly contracted third party well will startto flow late in the fourth quarter of this year.  Other third party wells that have not been flowing due to a thirdparty title dispute started flowing in the third quarter.  By early 2002, the throughput volumes shouldbe 15,000 to 20,000 Mcfd.

 

In the Exploration and Production segment, the company expects naturalgas production to average 35,000 Mcfed in 2002 compared to the anticipated13,000 Mcfed in 2001.  Over 50exploitation wells are planned in Canada and the United States.  This 2002 production level is approximatelythe same as natural gas shrinkage needs for our midstream business andconstitutes a natural hedge, which should mitigate future earnings volatility.

 

EBITDA for the year 2002 is expected to be about $40 million, with theassumption that natural gas averages $3.00 per MMBtu at Henry Hub and WestTexas Intermediate oil averages $21.00 per barrel.  NGL pricing has a very high correlation to crude oil pricing.  The 2001 EBITDA is expected to be about $20million.

 

Pending new projects, capital expenditures for the Gas Processing andMarketing segment are expected to be nominal for 2002 compared with ananticipated level of $13 million in 2001. The Exploration and Production segment plans expenditures of about $20million compared with $13 million in 2001 (not including the $50 millionCanadian acquisition).    These aresplit about two-thirds to Canada and one-third to the U.S.

 

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

 

Reference is made toCommodity Price Risk Management in Item 2 of this Form 10-Q.

 

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

 

**Item1.  Legal Proceedings**

 

(a)       Aswe reported in a current report on Form 8-K, dated February 22, 2001, threecomplaints have been filed against us in the Circuit Court of Wayne County,West Virginia, by Columbia Gas Transmission Corporation and Columbia NaturalResources, Inc.; Equitable Production Company and Equitable Energy, LLC; andCobra Petroleum Production Company et al. These complaints each allege breach of contract and seek various formsof relief (including injunctive relief) and damages.

 

InJuly 2001, MarkWest has filed an action in the Denver District Court, inDenver, Colorado, against Columbia Gas Transmission Corporation and ColumbiaNatural Resources, Inc.; Equitable Production Company and Equitable Energy,LLC; and Cobra Petroleum Production Company et al to compel arbitration onthese matters in accordance with provisions in existing contracts.  In August 2001, the Circuit Court of WayneCounty, West Virginia, granted the plaintiff’s motion for a temporary mandatoryinjunction requiring MarkWest to return natural gas to producers in accordancewith contractual commitments.  Theruling has no impact, as MarkWest has continually returned natural gas inaccordance with its agreement.  MarkWesthas requested reconsideration of certain aspects of the ruling.  In addition, a trial date has been scheduledfor February 2002.  MarkWest iscontinuing settlement negotiations with various parties.

 

Inthe winter of 2000-2001, current and futures prices for natural gas had risendramatically relative to prices for NGLs (propane, butane, etc.).  A large portion—about 75 percent—ofMarkWest’s processing services for gas producers in Appalachia involves extractingNGLs from inlet gas streams and replacing the equivalent heat content with drynatural gas purchased in the spot or forward markets.  This part of our operating margin depends on a positive spreadbetween NGL prices and natural gas costs. Effective February 1, 2001, we provided producers with an alternativeprocessing contract that provides for additional compensation to MarkWest whenprocessing margins are low and reduced compensation when these margins arehigh.  To date, over 90 producers (accountingfor a minority share of the volume) have agreed to an amended contract.  If producers elect to remain with theexisting contract, we have stated that we will return the replacement naturalgas at a later date.  We believe this ispermitted under the existing contract such that we can earn a reasonable feefor our services.

 

Sincethe winter of 2000-2001, the relationship between NGLs and natural gas hasimproved substantially.

 

(b)       OnJune 6, 2001, Level Propane Gases, Inc. filed suit against MarkWestHydrocarbon, Inc. in the Court of Common Pleas, Cuyahoga County, Ohio allegingbreach of contract for failure to furnish a specified quantity of gallons ofpropane gas on a monthly basis from May 1, 2000 to April 30, 2001, and seekingdirect and punitive damages.

 

OnJuly 25, 2001, MarkWest filed a Motion to stay proceedings pending arbitrationin Denver, Colorado in the Court of Common Pleas, Cuyahoga County, Ohio.

 

MarkWestbelieves Level’s breach of contract claim has no merit.

 

**Item6.  Exhibits and Reports on Form 8-K**

 

(a)   Exhibits

11 — Statement regardingcomputation of earnings per share.

 

## **(b)   Reports on Form8-K**

## **(i)            A report on Form 8-K was filed on August 14, 2001,announcing the acquisition of two Canadian**

## **                natural gas production companies.**

## **(ii)           A report on Form 8-K was filed August 27, 2001, presentingthe purchase and sale and financing**

## **                agreements on the acquisition of the two Canadiancompanies announced on August 14, 2001.**

## **(iii)          A report on Form 8K/A was filed on October 24, 2001, presentingaudited financial statements of the**

## **                two Canadian companies acquired in August 2001 andpro forma financials for MarkWest.**

## ** **

## **SIGNATURE**

 

Pursuant to therequirements of the Securities Exchange Act of 1934, MarkWest, as registrant,had this report signed on our behalf by the undersigned, who has been dulyauthorized.

 
|                           | MarkWest Hydrocarbon,  Inc. |
|--------------------------------|-----------------------------|
|                           |                        | (Registrant) |
|                           |                        |   |
|                           |                        |   |
| Date:   November 12, 2001 | By:                         | /s/ Gerald A. Tywoniuk |
|                           |                        | Gerald A. Tywoniuk |
|                           |                        | Chief Financial Officer and Vice President Of  Finance |
|                           |                        | (On Behalf of the Registrant and as Principal  Financial Officer) |