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**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION****Washington, D.C. 20549**

**FORM10-Q**

| ý | **QUARTERLY REPORT PURSUANT TO SECTION 13 or  15(d)** |
|--------|-------------------------------------------------------|
|   | **OF THE SECURITIES EXCHANGE ACT OF 1934**            |

**For the quarterly period endedJune 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.******(Exact name ofregistrant 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 theregistrant (1) has filed all reports required to be filed by Section 13 or15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (orfor such shorter period that the registrant was required to file such reports),and (2) has been subject to such filing requirements for the past 90 days.Yes ý  No o

The registrant had 8,474,283 shares ofcommon stock, $.01 per share par value, outstanding as of June 30, 2001.

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| **PART I—FINANCIAL  INFORMATION**                                                                     |
|------------------------------------------------------------------------------------------------------------|
|                                                                                                       |   |
| Item 1.  Consolidated Financial Statements                                                            |
|                                                                                                       | Consolidated Balance Sheet  at June 30, 2001 and December 31, 2000 |
|                                                                                                       | Consolidated  Statement of Operations for the Three and Six Months Ended June 30, 2001 and  2000 |
|                                                                                                       | Consolidated  Statement of Cash Flows for the Three and Six Months Ended June 30, 2001 and  2000 |
|                                                                                                       | Consolidated  Statement of Changes in Shareholder’s Equity for the Three and Six Months  Ended June 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  4.  Submission of Matters to a Vote of  Security Holders                                        |
| Item 6.  Exhibits and Reports on Form 8-K                                                             |
|                                                                                                       |   |
| **SIGNATURE**                                                                                              |
|                                                                                                            |  |  |

 

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| **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 |
| 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. |

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**PART I—FINANCIAL INFORMATION****Item 1.  Consolidated Financial Statements**

**MARKWESTHYDROCARBON, INC.CONSOLIDATED BALANCE SHEET(UNAUDITED)(000s, except share data)**

| **ASSETS**                                                                         | June  30,  2001                                                                                                    |    | December  31,  2000 |    |
|------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------|---------|---------------------|---------|
|                                                                               |                                                                                                                    |    |                     |    |
| Current assets:                                                                    |                                                                                                               |    |                |    |
|                                                                               | Cash and cash  equivalents                                                                                         | $       | 2,391               |    | $ | 934 |   |
|                                                                               | Receivables                                                                                                        | 15,960  |                | 36,695  |   |
|                                                                               | Inventories                                                                                                        | 5,248   |                | 8,058   |   |
|                                                                               | Risk management asset                                                                                              | 1,662   |                | —  |   |
|                                                                               | Other assets                                                                                                       | 1,082   |                | 913     |   |
|                                                                               |                                                                                                               |         |                |         |   |
|                                                                               | Total current assets                                                                                               | 26,343  |                | 46,600  |   |
|                                                                               |                                                                                                               |    |                |    |
| Property and  equipment:                                                           |                                                                                                               |    |                |    |
|                                                                               | Gas processing,  gathering, storage and marketing equipment                                                        | 99,058  |                | 97,311  |   |
|                                                                               | Oil and gas properties  and equipment                                                                              | 23,470  |                | 18,037  |   |
|                                                                               | Land, buildings and  other equipment                                                                               | 6,536   |                | 6,463   |   |
|                                                                               | Construction in  progress                                                                                          | 14,730  |                | 6,241   |   |
|                                                                               |                                                                                                               |         |                |         |   |
|                                                                               | 143,794                                                                                                            |    | 128,052             |    |
|                                                                               | Less: accumulated  depreciation, depletion and amortization                                                        | (31,015 | )                   | (27,833 | ) |
|                                                                               |                                                                                                                    |    |                     |    |
|                                                                               | Total property and  equipment, net                                                                                 | 112,779 |                | 100,219 |   |
|                                                                               |                                                                                                               |    |                |    |
| Risk management asset                                                              | 725                                                                                                                |    | —              |    |
| Intangible assets, net  of accumulated amortization of $924 and $708, respectively | 253                                                                                                                |    | 468                 |    |
|                                                                               |                                                                                                                    |    |                     |    |
|                                                                               |                                                                                                               |    |                |    |
|                                                                               | Total assets                                                                                                       | $       | 140,100             |    | $ | 147,287 |   |
|                                                                               |                                                                                                               |         |                |         |   |
|                                                                               |                                                                                                               |    |                |    |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                     |                                                                                                               |    |                |    |
|                                                                               |                                                                                                               |    |                |    |
| Current liabilities:                                                               |                                                                                                               |    |                |    |
|                                                                               | Accounts payable                                                                                                   | $       | 8,764               |    | $ | 17,713 |   |
|                                                                               | Accrued liabilities                                                                                                | 8,114   |                | 13,740  |   |
|                                                                               | Risk management  liability                                                                                         | 405     |                | —  |   |
|                                                                               |                                                                                                               |         |                |         |   |
|                                                                               | Total current  liabilities                                                                                         | 17,283  |                | 31,453  |   |
|                                                                               |                                                                                                               |    |                |    |
| Deferred income taxes                                                              | 12,327                                                                                                             |    | 11,240              |    |
| Long-term debt                                                                     | 46,000                                                                                                             |    | 43,000              |    |
|                                                                               |                                                                                                               |    |                |    |
| Commitments and  contingencies (See Note 4)                                        | —                                                                                                             |    | —              |    |
|                                                                               |                                                                                                               |    |                |    |
| 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 8,563,919 shares issued,  respectively | 87      |                | 86      |   |
|                                                                               | Additional paid-in  capital                                                                                        | 42,539  |                | 42,471  |   |
|                                                                               | Retained earnings                                                                                                  | 21,136  |                | 19,679  |   |
|                                                                               | Accumulated other  comprehensive income                                                                            | 1,279   |                | —  |   |
|                                                                               | Treasury stock, 89,636  and 104,093 shares, respectively                                                           | (551    | )                   | (642    | ) |
|                                                                               |                                                                                                               |         |                |         |   |
|                                                                               | Total stockholders’  equity                                                                                   | 64,490  |                | 61,594  |   |
|                                                                               |                                                                                                               |         |                |         |   |
|                                                                               |                                                                                                               |    |                |    |
|                                                                               | Total liabilities and  stockholders’ equity                                                                   | $       | 140,100             |    | $ | 147,287 |   |
|                                                                               |                                                                                                               |         |                |         |   |
|                                                                                    |                                                                                                                    |         |                     |         |  |  |  |  |

The accompanying notes are an integral part of thesefinancial statements****MARKWESTHYDROCARBON, INC.CONSOLIDATED STATEMENT OF OPERATIONS(UNAUDITED)(000s, except per share data)**

 
 For  the three months ended  June 30, For  the six months ended  June 30,     2001 2000 2001 2000      Revenue:         Gathering, processing  and marketing$28,541 $38,788 $114,058 $83,483  Exploration and  production2,337 1,069 5,036 1,818        Total revenue30,878 39,857 119,094 85,301          Operating expenses:         Cost of sales22,830 30,962 98,675 63,292  Operating expenses3,980 4,083 8,997 7,889  General and  administrative expenses1,858 2,018 4,283 3,857  Depreciation,  depletion and amortization1,680 1,461 3,405 2,896        Total operating  expenses30,348 38,524 115,360 77,934                 Income from operations530 1,333 3,734 7,367          Other income and  expense:         Interest income58 30 82 53  Interest expense(539)(655)(1,260)(1,402) Gain on sale of assets— 1,000 — 1,000  Other income (expense)(115)77 (248)103                 Income (loss) before  income taxes(66)1,785 2,308 7,121                Provision for income  taxes:         Current(41)373 468 1,518  Deferred(33)305 383 1,241        Provision for income  taxes(74)678 851 2,759                 Net income$8 $1,107 $1,457 $4,362                Basic earnings per  share of common stock$0.00 $0.13 $0.17 $0.52       Earnings per share  assuming dilution$0.00 $0.13 $0.17 $0.51                Weighted average  number of outstanding shares of common stock:         Basic8,473 8,451 8,469 8,452        Assuming dilution8,489 8,483 8,498 8,475       
The accompanying notes are an integral part of thesefinancial statements
**MARKWESTHYDROCARBON, INC.CONSOLIDATED STATEMENT OF CASH FLOWS(UNAUDITED)(000s)**

 
 For  the three months  ended June 30, For  the six months  ended June 30,     2001 2000 2001 2000      Cash flows from  operating activities:         Net income$8 $1,107 $1,457 $4,362  Add income items that  do not affect working capital:         Depreciation,  depletion and amortization1,680 1,461 3,405 2,896  Deferred income taxes(33)305 383 1,241  Gain on sale of assets— (1,000)— (1,000) Other(5)(9)4 (137)       1,650 1,864 5,249 7,362           Adjustments to working  capital:         (Increase) decrease in  receivables10,609 (3,364)20,735 (61) (Increase) decrease in  inventories(1,935)(3,010)2,810 (718) (Increase) decrease in  prepaid expenses and other assets210 (2,099)(169)(2,256) Increase (decrease) in  accounts payable and accrued liabilities(6,485)1,127 (14,593)7,093        2,399 (7,346)8,783 4,058           Net cash flow provided  by operating activities4,049 (5,482)14,032 11,420          Cash flows from  investing activities:         Capital expenditures(6,230)(2,728)(15,756)(9,288) Proceeds from sale of  assets20 1,399 20 6,484                 Net cash used in  investing activities(6,210)(1,329)(15,736)(2,804)         Cash flows from  financing activities:         Proceeds from  long-term debt10,500 15,000 33,500 20,500  Repayment of long-term  debt(8,500)(9,049)(30,500)(28,639) Exercise of stock  options— — 18 —  Acquisition of  treasury stock23 19 143 (52) Reissuance of treasury  stock— (263)— (263)                Net cash provided by  financing activities2,023 5,707 3,161 (8,454)     Net increase in cash  and cash equivalents(138)(1,104)1,457 162          Cash and cash  equivalents at beginning of period2,529 2,622 934 1,356               Cash and cash  equivalents at end of period$2,391 $1,518 $2,391 $1,518      
The accompanying notes are an integral part of thesefinancial statements****MARKWESTHYDROCARBON, INC.CONSOLIDATED STATEMENT OFCHANGES INSTOCKHOLDERS’ 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,  20008,561 (104)$86 $42,471 $19,679 $(642)$0 $61,594                  Transition adjustment— — — — — — (1,230)(1,230)                 Net income— — — — 1,449 — — 1,449                  Risk management  activities— — — — — — 281 281                                  Comprehensive income              $1,730                                  Exercise of options3 — 1 17 — — — 18                  Reissuance of treasury  stock— 11 — 49 — 71 — 120                           Balance, March 31, 20018,564 (93)$87 $42,537 $21,128 $(571)$(949)$62,232                           Net income— — — — 8 — — 8                  Risk management  activities— — — — — — 2,228 2,228                                  Comprehensive income— — — — — — — $2,236                                  Reissuance of treasury  stock— 3 — 2 — 20 — 22                           Balance, June 30, 20018,564 (90)$87 $42,539 $21,136 $(551)$1,279 $64,490          
The accompanying notes are an integral part of thesefinancial statements
**NOTE1.  GENERAL**

The consolidated financial statementsinclude the accounts of MarkWest Hydrocarbon, Inc. (“MarkWest”), and its whollyowned subsidiaries:

•            MarkWestResources, Inc.

•            MarkWestMichigan, Inc.

•            BasinPipeline, LLC

•            WestShore Processing Company, LLC

•            Matrex,LLC

Through consolidation, we have eliminatedall significant intercompany accounts and transactions.

We have prepared the unaudited financialstatements presented herein in accordance with the instructions to Form10-Q.  The statements do not include allthe information and note disclosures required by generally accepted accountingprinciples for complete financial statements. Please read the interim consolidated financial statements in conjunctionwith the Consolidated Financial Statements and attached notes for the yearended December 31, 2000, included in the Company’s Annual Report on Form 10-K,as filed with the Securities and Exchange Commission.  In the opinion of management, we have made all necessaryadjustments for a fair statement of the results for the unaudited interim periods.  These are only normal recurring adjustments.

We base the effective corporate tax ratefor interim periods on the estimated annual effective corporate tax rate,excluding certain nonrecurring or unusual events.  The effective tax rate varies from statutory rates primarily dueto tax credits.

We have reclassified certain prior-yearamounts to conform to the current year’s presentation.

**NOTE 2.  RECENT ACCOUNTING PRONOUNCEMENTS**

In June 1998, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards(“SFAS”) No. 133, *Accounting for DerivativeInstruments and Hedging Activities*. This statement, as amended by SFAS Nos. 137 and 138, is effective forfiscal years beginning after June 15, 2000. SFAS No. 133 requires an entity to recognize all derivatives as assetsor liabilities in the balance sheet and measure those instruments at fairvalue.  MarkWest has adopted SFAS No.133, as amended, on January 1, 2001. See Note 5 Adoption of SFAS No. 133.

In July 2001, the FASB issued Statementof Financial Accounting Standards No. 143, *Accountingfor Asset Retirement Obligations*(“SFAS 143”).  SFAS 143, is effective for fiscal yearsbeginning after June 15, 2002 (January 1, 2003 for MarkWest), and establishesan accounting standard requiring the recording of the fair value of liabilitiesassociated with the retirement of long-lived assets in the period in which theyare incurred.  We are in the process ofdetermining the future impact that the adoption of FAS 143 may have on ourearnings and financial position.

**NOTE3.   SEGMENT REPORTING**

We classify MarkWest’s operations intotwo reportable segments, as follows:
 (1)Gathering,  Processing and Marketing (“GPM”)—provide compression, gathering, treatment,  NGL extraction and fractionation services; also purchase and market natural  gas and NGLs; and (2)Exploration  and Production (“E & P”)—explore for and produce natural gas.
 

We evaluate the performance of oursegments and allocate resources to them based on operating income. There are nointersegment revenues.  We conduct ourbusiness solely in the United States. Subsequent to our recent acquisition discussed in Note 6, MarkWest willalso be conducting business in Canada.
The table below presents informationabout operating income for the reported segments for the second quarter of 2001and 2000 and for the six months ended June 30, 2001 and 2000.  Operating income for each segment includestotal revenues less operating expenses and excludes depreciation, depletion andamortization, general and administrative expenses, interest expense, interestincome and income taxes.  We have notreported asset information by reportable segment, since we do not produce suchinformation internally.

 
 Gathering,  Processing and  Marketing (000s) Exploration  and  Production  (000s) Total  (000s)     **For the Quarter ended June  30, 2001:**      Revenues$28,541 $2,337 $30,878 Segment operating  income$2,512 $1,556 $4,068        **For the Quarter ended June  30, 2000:**      Revenues$38,788 $1,069 $39,857 Segment operating  income$4,549 $263 $4,812        **For the six months ended June  30, 2001:**      Revenues$114,058 $5,036 $119,094 Segment operating  income$7,877 $3,545 $11,422        **For the six months ended June  30, 2000:**      Revenues$83,483 $1,818 $85,301 Segment operating  income$13,544 $576 $14,120 
Following is a reconciliation of totalsegment operating income to total consolidated income before taxes (000s): 
 For  the quarter ended  June 30, For  the six months ended  June 30,     2001 2000 2001 2000      Total segment  operating income$4,068 $4,812 $11,422 $14,120 General and  administrative expenses(1,858)(2,018)(4,283)(3,857)Depreciation and  amortization(1,680)(1,461)(3,405)(2,896)Interest income58 30 82 53 Interest  expense(539)(655)(1,260)(1,402)Gain  on sale of assets— 1,000 — 1,000 Other  income (expense)(115)77 (248)103       Income  (loss) before taxes$(66)$1,785 $2,308 $7,121      
**NOTE 4.  CONTINGENCY**

In February 2001, three complaints werefiled against MarkWest Hydrocarbon, Inc., 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 Company et al.  Thesecomplaints each allege breach of contract and seek various forms of relief(including injunctive relief) and damages. Losses, if any, with regard to these complaints are undeterminable.  In July 2001, MarkWest filed an action inthe Denver District Court, Denver, Colorado, against Columbia Gas Transmission Corporationand Columbia Natural Resources, Inc.; Equitable Production Company andEquitable Energy, LLC; and Cobra Petroleum Production Company et al., to compelarbitration on these matters in accordance with provisions in existingcontracts.

**NOTE 5.  ADOPTION OFSFAS NO. 133**

MarkWest adopted SFAS No. 133, *Accountingfor Derivative Instruments and Hedging Activities*, as amended, onJanuary 1, 2001.  In accordance with thetransition provisions of SFAS 133, we recorded on that date a net-of-taxcumulative effect adjustment of approximately $1.2 million loss to othercomprehensive income to recognize at fair value all derivatives that aredesignated as cash-flow hedging instruments.
SFAS 133 establishes accounting andreporting standards requiring derivative instruments to be recorded in thebalance sheet as either an asset or liability measured at fair value.  Changes in the derivative instruments’ fairvalue are recognized in earnings unless specific hedge accounting criteria aremet.

SFAS 133 allows hedge accounting forfair-value and cash-flow hedges.  Afair-value hedge applies to a recognized asset or liability or an unrecognizedfirm commitment.  A cash-flow hedgeapplies to a forecasted transaction or a variable cash flow of a recognizedasset or liability.  SFAS 133 providesthat the gain or loss on a derivative instrument designated and qualifying as afair-value hedging instrument as well as the offsetting loss or gain on thehedged item be recognized 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 inearnings.)  Effectiveness is evaluated bythe derivative instrument’s ability to generate offsetting changes in fairvalue or cash flows to the hedged item. We formally document, designate and assess the effectiveness oftransactions receiving hedge accounting treatment.

In our gathering, processing andmarketing segment, we enter into fixed-price contracts for the sale of NGLs andfixed-price purchases for the purchase of natural gas and NGLs.  At January 1, 2001, we recorded a riskmanagement asset of approximately $2.1 million in the balance sheet with anoffsetting amount recorded, less a deferred tax liability of approximately $0.7million, in other comprehensive income— approximately $1.3 million gain.  At June 30, 2001, the risk managementliability was $108,000, less $38,000 deferred tax recovery, resulting in a$70,000 loss in other comprehensive income. We also recorded a $0.4 million risk management liability and acorresponding risk management asset to reflect our fair value hedges.

In our exploration and productionsegment, MarkWest enters into fixed-price contracts for the sale of naturalgas.  At January 1, 2001, we recorded arisk management liability of approximately $3.9 million in the balance sheetwith an offsetting amount recorded, less a deferred tax recovery ofapproximately $1.4 million, in other comprehensive income—approximately $2.5million loss.  At June 30, 2001, therisk management asset was $2.0 million, less $0.7 million deferred taxliability, resulting in a $1.3 million gain in other comprehensive income.

During the second quarter of 2001, wehave entered into three year contracts to fix interest rates on $10 million ofour debt at 5.28% compared to a floating LIBOR (in both cases, plus anapplicable margin).  At June 30, 2001,we recorded a risk management asset of approximately $40,000 in the balance sheetwith an offsetting amount recorded, less a deferred tax liability ofapproximately $14,000, and in other comprehensive income, approximately$26,000.

Together, at January 1, 2001, theseamounts comprise the above net-of-tax cumulative effect adjustment ofapproximately $1.2 million loss to other comprehensive income.  At June 30, 2001, with all transactionsconsidered, there is a $1.3 million gain to accumulated comprehensive income.

**NOTE6.  SUBSEQUENT EVENT**

On August 10, 2001, MarkWest Hydrocarbonacquired two privately-owned independent exploration and production companies,Leland Energy Canada Ltd. and Watford Energy Ltd., for $51 million.

Our credit facility has been expandedfrom $65 million to $130 million to provide funding for the acquisition.  The new credit facility is comprised ofthree components:  1.) a $40 million,four-year term loan; 2) a $55 million revolving facility which converts toreducing status on December 31, 2003, maturing August 2005; and 3.) a $35million revolving facility to be replaced with a six-year Canadian facility byOctober 2001.

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

This Management’s Discussion and Analysiscontains statements which, to the extent that they are not recitations ofhistorical fact, constitute “forward-looking statements” within the meaning ofSection 27A of the Securities Act of 1933 (“Section 27A”) and Section 21E ofthe Securities and Exchange Act of 1934 as amended (“Section 21E”).  This includes, among other things,statements with respect to the outcome of the pending litigation matters andcontract negotiations.  Allforward-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 in regions where our products are located  •the  availability and prices of NGL and competing commodities  •the  availability and prices of raw natural gas supply  •our  ability to negotiate favorable marketing agreements  •the  risks that third party or MarkWest’s natural gas exploration and production  activities will not occur or be successful  •our  dependence on certain significant customers, producers, gatherers, treaters  and transporters of natural gas  •competition  from other NGL processors, including major energy companies  •our  ability to identify and consummate grass-roots projects or acquisitions  complementary to our business  •winter  weather conditions  •intermediate  or final decisions in the pending litigation and the relative positions of  the parties in the negotiation of new processing agreements  •our  ability to integrate the recent Canadian acquisition to operate an  exploration and production company in Canada, and to manage the Company as a  more exploration and production focused enterprise.
Forward-looking statements involve manyuncertainties that are beyond our ability to control.  In many cases, we cannot predict what factors would cause actualresults to differ materially from those indicated by the forward-lookingstatements.

**Three Months Ended June 30, 2001, Compared to the ThreeMonths Ended June 30, 2000 (in 000s)**
 2001 2000 $  Change     Revenues$30,878 $39,857 $(8,979)Income from operations$530 $1,333 $(803)       Income (loss) before  income taxes$(66)$1,785 $(1,851)Provision (benefit)  for income taxes(74)678 752     Net income$8 $1,107 $(1,099)           Net income, excluding  gain on sale of assets$8 $487 $479            Basic earnings per  share$0.00 $0.13 $(0.13)Basic earnings per  share, excluding gain on sale of assets$0.00 $0.06 $(0.06)
The strongest demand for propane, andconsequently the highest volumes of and margins for propane sales, generallyoccur in the winter heating season. Therefore, a substantial portion of our net income is recognized in thefirst and fourth quarters.  Thisseasonality occurs in the GPM segment of our business.

For the quarter ended June 30, 2001, wereport break even results, or $0.00 per share, compared to net income,excluding gain on sale, of $0.5 million, or $0.06 per share, for the sameperiod last year.  Earnings beforeinterest, taxes and depreciation, depletion and amortization (“EBITDA”) was$2.1 million versus $2.9 million in the second quarter of 2001 and 2000,respectively.

MarkWest’s Appalachian operationsexperienced a lower spread between the price of the NGLs versus the cost of thenatural gas than in the previous year. The margin was a more normal $0.13 per gallon versus an above average$0.17 per gallon, or $0.7 million less margin in second quarter 2001.  Sales volumes were 25.7 million gallonsversus 32.8 million gallons, down 22 percent from second quarter 2000 to 2001.  This unfavorable volume variance translatesto $0.9 million less margin in second quarter 2001.  The decline was due to a longer maintenance shutdown of theKenova plant to complete an expansion; input pipeline maintenance; weatherrelated shutdowns of producer wells; and delays of additional third-partycompression facilities.  Productionthough is expected to be operating at our newly expanded plant capacities bythe end of the third quarter 2001. Michigan GPM cash operating income was lower by $0.4 million primarilydue to the lower volumes in Michigan this year.  The E&P segment was $1.5 million ahead of last year due tothe Au Gres well coming on line in July 2000; and in the Rocky MountainE&P business unit, higher volume and prices as well as the San Juanproperty acquired earlier this year, improved 2001 results.  Operating expenses as well as the generaland administrative expenses were slightly lower in 2001 than the same periodlast year.
**Six Months Ended June 30, 2001, Compared to the Six MonthsEnded June 30, 2000 (in 000s)**
 2001 2000 $  Change     Revenues$119,094 $85,301 $33,793 Income from operations$3,734 $7,367 $(3,633)       Income before income  taxes$2,308 $7,121 $(4,813)Provision for income  taxes851 2,759 1,908     Net income$1,457 $4,362 $(2,905)    Net income, excluding  gain on sale of assets$1,457 $3,742 $(2,285)           Basic earnings per  share$0.17 $0.52 $(0.35)       Basic earnings per  share, excluding gain on sale of assets$0.17 $0.44 $(0.27)
For the six months ended June 30, 2001,we report net income of $1.5 million, or $0.17 per share, compared to netincome, excluding gain on sale, of $3.7 million, or $0.44 per share, for thesame period last year.  Earnings beforeinterest, taxes and depreciation, depletion and amortization (“EBITDA”) was$6.9 million versus $10.4 million in 2001 and 2000, respectively.

MarkWest’s Appalachian operationsexperienced a lower spread between the price of the NGLs versus the cost of thenatural gas than in the previous year. The margin was a more normal $0.15 versus an above average $0.21, adifference of $0.06 per gallon, or $2.9 million less margin in 2001.  The $0.15 margin per gallon earned in 2001is comparable to the ten year average of $0.16 margin per gallon.  Michigan GPM cash operating income was lowerby $0.6 million primarily due to the lower volumes in Michigan this year.  The E&P segment was $3.0 million aheadof last year due to the Au Gres well coming on line in July 2000 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 increases related to the capital expansions andacquisitions since last year.

**Operating data**
 **Three Months Ended June 30,** **Six Months Ended June 30,**  **** ****  **2001** **2000** **% Change** **2001** **2000** **% Change**  **** **** Gathering, processing and marketing            Appalachia:             NGL  production—Siloam plant (gallons)32,800,000 40,500,000 (19)%72,100,000 73,800,000 (2)% NGL  sales—Siloam plant (gallons)25,700,000 32,800,000 (22)%71,000,000 69,700,000 (2)% Processing  margin per gallon:             Average  NGL sales price$0.54 $0.53 2%$0.62 $0.56 11% Average  natural gas cost0.41 0.36 14%0.47 0.35 34%     Processing  margin per gallon$0.13 $0.17 (24)%$0.15 $0.21 (29)             Michigan:             Pipeline  throughput (Mcfd)7,600 12,300 (38)%7,900 12,800 (38)% NGL  sales (gallons)1,600,000 2,400,000 (33)%3,500,000 5,200,000 (33)%Exploration  and production:             Natural  gas produced (Mcfd)6,100 3,200 91%6,300 3,300 91%
**Gathering, Processing and Marketing  (GPM)**

We are paid for our processing inAppalachia through sales of liquids extracted and fees for units ofthroughput.  A large portion, about 75percent, of our processing services for gas producers in Appalachia involvesextracting NGLs from inlet gas streams and replacing the equivalent heatcontent with dry natural gas purchased in the spot or forward market.   Consequently, this segment of our businessdepends on a positive spread between the NGL prices and the cost of thereplacement natural gas (“processing margin”).
The operating income for the GPM segmentof MarkWest was $2.5 million for the second quarter and almost $7.9 million foryear to date 2001.  This compares with$4.5 million for the second quarter of 2000 and $13.5 million for year to date2000.

A lower spread between the price of theNGLs versus the cost of the natural gas negatively impacted our gross marginsin Appalachia.   The unfavorable pricevariance in second quarter was $0.9 million. Volumes sold at our Siloam fractionator during the second quarter are 22percent lower than the same quarter last year, but on a year-to-date basis, thevolume variance is negligible, less than 2 percent.  The volumes were lower in the second quarter due to a longermaintenance shutdown at the Kenova plant to complete an expansion, inputpipeline maintenance, weather related shutdowns of producer wells, and delaysof additional compression facilities. The unfavorable volume variance in the second quarter was $1.1 million.

Earlier in the year 2001, there was adramatic decline in the prices of NGLs that triggered a sizable write down ofinventory value at our Appalachia propane terminals negatively impacting theAppalachian gross margins in 2001.

In Western Michigan, our volumes weredown 38 percent for the quarter and year to date when compared to the prioryear same periods.  Volumes in westernMichigan were lower because no new pipeline connections were made and there isa natural depletion in the performance of the existing wells.  This reduced gross margins by $0.5 millioncompared to the same quarter last year.  The year-to-date throughput volumes are 7,900 Mcfd compared to lastyear’s throughput volumes of 12,800 Mcfd. Litigation surrounding another third party well was settled very late inthe second quarter 2001 and the additional volumes, currently producing 2,000Mcfd, will be realized beginning in the third quarter of 2001.  MarkWest, along with industry partners, madetwo discoveries during second quarter that should provide additional volume inthe fourth quarter 2001.  Another largewell was recently contracted and is anticipated to be on stream during thefourth quarter this year.  By year-end,our throughput volumes are expected to be more than 20,000 Mcfd.

**Exploration and Production (E & P)**

2001 has been an exciting six months forour E&P segment.   Unprecedentedhigh natural gas prices, an acquisition, a new project in eastern Michigan, asecond well at Au Gres, and the benefits of our prior year capital investmentshave all favorably impacted the operating income for this segment.

The operating income for the E&Psegment of MarkWest was $1.6 million for the second quarter and $3.5 millionyear to date 2001.   This comparesfavorably with $0.3 million for the second quarter of 2000 and $0.6 million foryear to date 2000.

The volumes have increased ninety percentor more compared to the prior year volumes.  The acquisition of the Kutz field in the San Juan Basin of New Mexicothat closed early this year, a new recompletion well in eastern Michigan, andthe infill well drilling and recompletion program initiated last year in theSan Juan Basin of Colorado all contributed to the additional volumes this pastquarter.  The residual variance isrelated to the unprecedented high natural gas prices.  We are currently preparing to recomplete the third Au Gres well.

**Revenues and Expenses**

*Revenues*Revenues increased from $85.3 million to $119.1 million year to date 2000compared to 2001.  During secondquarter, the revenues are $9.0 million lower in 2001 compared to 2000.

Gas marketing activities are low margintransactions done in support of our processing business.  The volume and gross margins have increasedthis year.   The 2001 year-to-date gasmarketing revenues are $17.1 million ahead of last year the same time, a 57percent increase.  However, secondquarter revenues are $10.2 million behind second quarter 2000 revenues, butthis low margin activity imparted operating profit only negligibly.

Appalachia GPM, excluding gas marketingactivities previously mentioned, had revenues of  $50.1 million year to date 2001 compared to $42.6 million year todate 2000.  The increase from year toyear is predominantly in the product sales price.  The prices have increased from $0.56 per gallon to $0.62 pergallon in 2001.  For the second quarter,revenues are actually lower in 2001 than 2000 by $3.0 million due to fewersales gallons than last year.
Michigan GPM provided an additional $4.5million to 2001 revenues compared to 2000 year-to-date revenues with $1.4million of that additional revenue in the second quarter.  Throughput volumes were down 38 percentduring the second quarter and for the year 2001, compared to last year’svolumes.  The decrease in volumes effecton revenues was more than offset by higher prices.  This volume decline is expected to turn around later this yearbecause of new wells being added to the system.  We also chose to deplete on hand inventory in 2001.

Michigan E&P revenues for the secondquarter 2001 are $0.6 million and $1.3 million for the three and six monthsended June 30, 2001.  The second quarter2001 revenues were $0.5 million higher than the same quarter last year.  This is the result of the Au Gres wellcoming on line in July 2000.

Rocky Mountain E&P contributed anadditional $2.0 million to year-to-date 2001 revenues and $0.8 of that was inthe second quarter of 2001.  Theadditional revenue base is the result of unprecedented high natural gas prices,higher volumes due to an acquisition earlier this year, and the benefits oflast year’s capital expenditures.

*Cost of Sales*Cost of sales has decreased $8.0 million during the second quarter of 2001compared to 2000, but on a year-to-date basis, cost of sales increased from$63.3 million to $98.7 million.

Gas marketing cost of sales, likerevenues, are down $10.2 million in second quarter 2001 compared to 2000.  Gas marketing cost of sales are 56 percenthigher than last year at this time, relative to the 57 percent increase inrevenues mentioned above.  The gas marketingcost of sales are $16.6 million higher in 2001 than 2000.

Appalachia GPM cost of sales are $10.8million higher year to date than in year to date 2000.  The predominant cause of this increase isrelated to the feedstock cost increase.  In 2000,  the cost per gallon was$0.35 versus a cost of $0.47 for 2001.

Michigan GPM cost of sales were $5.5million higher in 2001 than in 2000 with $1.9 million of that occurring in thesecond quarter 2001.   The volumes weredown but the costs were higher per unit this year.

*Operating Expenses*Operating expenses increased from $7.9million year to date 2000 compared to $9.0 million year to date 2001; thesecond quarter’s operating expenses are $4.0 million in 2000 and 2001.  Much of the increased year-to-date costsrelate to the acquisitions and expansions from 2000 being on line for all of 2001as opposed to only part of 2000 as well as higher fuel costs in 2001.

*General and Administrative Expenses*General and administrative expenses increased from $3.9 million year to date2000 compared to $4.3 million in 2001. The second quarter expenses however are lower in 2001 than in 2000 by$0.2 million.  The second quarter costsavings are due to general cost cutting.

*Depreciation, Depletion and Amortization*Depreciation, depletion and amortizationincreased year to date by $0.5 million and during the second quarter itincreased $0.2 million.  The increase isdirectly related to the capital expenditures made in 2000 and early in 2001.

*Other income and expense*During thesecond quarter 2000, we sold an asset for a $1.0 million pre-tax gain.

**Liquidity and Capital Resources**

MarkWest’s sources of liquidity andcapital resources historically have been internal cash flow and our revolvingline of credit.  In the first quarter of2000, we supplemented these sources with proceeds from the sale of ourcorporate office building.  In thesecond quarter of 2000, we increased our line of credit by $15 million to $65million.
The following summary table reflects ourcomparative cash flows for the six months ended June 30, 2001 and 2000 (inthousands):
 For the  six months ended June 30,    2001 2000         Net cash provided by operating  activities before change in working capital$5,249 $7,362 Net cash provided by (used in)  operating activities from change in working capital$8,763 $4,058 Net cash provided by (used in)  investing activities$(15,736)$(2,804)Net cash used in financing  activities$3,161 $(8,454)
*Capital Investment Program*

MarkWestforecasts a baseline capital budget of $24.5 million in 2001.  In our gathering, processing and marketingsegment the 2001 capital budget includes $8 million for completion ofAppalachia’s Phase II expansion.  The2001 capital budget also includes $12 million for our exploration andproduction segment—$5 million for the acquisition of San Juan Basin propertiesin January 2001; up to $4 million for infill drilling in the San Juan Basin;and up to $3 million for further expansion of the Au Gres, Michigan,property.  These latter two expendituresare discretionary and could be reduced depending on capital availability.

*FinancingFacilities*

Financing activities consist primarily ofnet borrowings under MarkWest’s credit facility.  At June 30, 2001, we had $65 million of available credit, ofwhich we had utilized $43.6 million in net debt (debt less cash).  Depending on Appalachia processing marginsand the timing and amount of our capital projects, we may have to seekadditional sources of capital.  While webelieve that we will be able to secure additional financing on acceptableterms, if required, we have no assurance that we will be able to do so.

*SubsequentEvent*

See Note 6  SUBSEQUENT EVENT

**Commodity Price Risk Management**

MarkWest’s primary risk managementobjective is to reduce volatility in our cash flows.  Our hedging approach uses a statistical method that analyzesmomentum and average pricing over time and various fundamental data, such asindustry inventories, industry production, demand and weather.  Hedging levels increase with capital commitmentsand debt levels and when above-average margins exist.  We maintain a committee, including members of senior management,which oversees all hedging activity.

Weachieve our goals utilizing a combination of fixed-price forward contracts andfixed-for-float price 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 with counterpartiesthat are primarily of other energy companies. We conduct a standard credit review and have agreements with suchparties that contain collateral requirements. We use standardized swap agreements that allow for offset of positiveand negative exposures.  Net creditexposure is marked to market daily.  Weare subject to margin deposit requirements under OTC agreements (and NYMEXpositions).

The use of financial instruments mayexpose MarkWest to the risk of financial loss in certain circumstances,including instances when (a) sales volumes are less than expected, requiringmarket purchases to meet commitments; or (b) our OTC counterparties fail topurchase or deliver the contracted quantities of natural gas, NGLs, or crudeoil, or otherwise fail to perform.  Tothe extent that we engage in hedging activities, we may be prevented fromrealizing the benefits of favorable price changes in the physical market.  However, we are similarly insulated againstdecreases in such prices.

MarkWest hedges our basis risk fornatural gas, but we are generally unable to do so for NGLs.  Our basis risk stems from the geographicprice differentials between our sales locations and hedging contract deliverylocations.  Basis risk is the risk thatan adverse change in the hedging market will not be completely offset by anequal and opposite change in the price of the physical commodity being hedged.
In our gathering, processing and marketingsegment, we hedge Appalachia processing margins by using a combination ofmethods.  We protect margins bypurchasing natural gas priced on predetermined Btu differentials to propane orcrude, by simultaneously selling propane or crude oil and purchasing naturalgas, and by using swaps.  Crude oil ishighly correlated with certain NGL products. All projected margins on open positions assume the basis differentialsbetween crude oil, and NGLs are consistent with historical averages.  As of June 30, 2001, there are no gallonshedged for processing margin. Subsequent to June 30, 2001, we have hedged 22.6 million gallons formore than $0.20 per gallon processing margin for the balance of 2001 and 2002.

For certain Appalachia natural gas liquidpurchases, as of June 30, 2001, we have hedged 0.7 million and 1.1 millionwinter season gallons at $0.54 per gallon for 2001 and 2002, respectively.

Forcertain Appalachia natural gas sales, as of June 30, 2001, we have hedged488,000 and 54,000 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-pricedperiods.  We also have contracts topurchase certain quantities of our natural gas feedstock in advance of physicalneeds.

Inour exploration and production segment, we hedge our exposure to changes inmarket prices for our natural gas production. As of June 30, 2001, we had hedged 1,533,000, 908,000, and 632,000 MMBtuof natural gas sales at prices of $3.70, $3.85 and $3.81 per MMBtu for 2001,2002 and 2003, respectively.

MarkWest’s hedging strategy benefited ourafter-tax earnings compared to the situation of not hedging.  In the gathering, processing and marketingsegment, without hedging, net income would have been lower by $0.1 million and$1.2 million and higher by $0.3 million and $0.9 million for the three and sixmonths ended June 30, 2001 and 2000, respectively.  This impact considers only hedges of Appalachia processing marginand does not reflect other decisions made concerning when to buy natural gas orstore NGL production for sale in later months. In the exploration and production segment, without hedging, net incomewould have been higher by $0.1 million and $0.7 million for the three and six months ended June 30,2001.

We enter into speculative transactions onan infrequent basis.  Specific approvalby the Board of Directors is necessary prior to executing suchtransactions.  Speculative transactionsare marked to market at the end of each accounting period, and any gain or lossis recognized in income for that period. There were no such speculative activities for the quarters ended June30, 2001 and 2000.

**Outlook**

In the Appalachia GPM segment, weanticipate operating at our new expanded capacity by late in the third quarter2001.   Phase II of our expansionprogram is complete which involved building a new plant near our existing facilityin Kenova, West Virginia.   Planning forother new projects is well underway that could also have a large positiveimpact on revenues and ultimately net income.

Michigan GPM has also had some veryexciting news this past quarter.  Twonew discoveries made with industry partners should greatly improve Michiganvolumes in the third and fourth quarter of 2001.   The third party wells that have not been flowing for quite sometime have started flowing again and are producing 2,200 Mcfd.  Contract negotiations are complete and wefully expect another third party well to be contributing additional volumesbeginning October 2001.  By the end of2001, the throughput volumes should be more than 20,000 Mcfd, up from the previousestimate of 14,000 Mcfd.

Michigan E&P will be adding a secondAu Gres well at the end of July 2001 with production volumes anticipated at3,500 Mcfd net to MarkWest’s interests. Current plans provide for the recompletion of a third Au Gres well bythe end of 2001.

Rocky Mountain E&P continues to growwith continuous recompletion and restimulation projects.  We have a workover rig on site of the newproperty acquired earlier in 2001.

The production goal for E&P in totalis 10,000 Mcfd by year end prior to the acquisition described in Note 6.

With the Canadian acquisition of August10, 2001, the company added 15,000 Mcfd and 190 barrels of oil per day toMarkWest’s current net production volumes. The acquisition also added 300 new drillable locations on more than106,000 acres, with 80 percent considered exploitable.  The wells are relatively shallow, with highinitial production and a reserve life of five to seven years.  The future capital expenditures for the nexttwo years is anticipated to be $40 million to provide many additional drillablelocations.

 

**Item 3.  Quantitative and Qualitative Disclosuresabout Market Risk**

Reference is made to Risk ManagementActivities in Item 2 of this Form 10-Q.

**PARTII.   OTHER INFORMATION**

**Item1.  Legal Proceedings**

As we reported in a current report on Form8-K, dated February 22, 2001, three complaints have been filed against us inthe Circuit Court of Wayne County, West Virginia, by Columbia Gas TransmissionCorporation and Columbia Natural Resources, Inc.; Equitable Production Companyand Equitable Energy, LLC; and Cobra Petroleum Production Company et al.  These complaints each allege breach ofcontract and seek various forms of relief (including injunctive relief) anddamages.

In July 2001, MarkWest has filed anaction in the Denver District Court, in Denver, Colorado, against Columbia GasTransmission Corporation and Columbia Natural Resources, Inc.; EquitableProduction Company and Equitable Energy, LLC; and Cobra Petrleum ProductionCompany et al. to compel arbitration on these matters in accordance withprovisions in existing contracts.

In the winter of 2000-2001, current andfutures prices for natural gas had risen dramatically relative to prices forNGLs (propane, butane, etc.).  A largeportion—about 75 percent—of MarkWest’s processing services for gas producers inAppalachia involves extracting NGLs from inlet gas streams and replacing theequivalent heat content with dry natural gas purchased in the spot or forwardmarkets.  This part of our operating margindepends on a positive spread between NGL prices and natural gas costs.  Effective February 1, 2001, we providedproducers with an alternative processing contract that provides for additionalcompensation to MarkWest when processing margins are low and reducedcompensation when these margins are high. To date, over 90 producers (accounting for a minority share of thevolume) have agreed to an amended contract. If producers elect to remain with the existing contract, we have statedthat we will return the replacement natural gas at a later date.  We believe this is permitted under theexisting contract such that we can earn a reasonable fee for our services.

Since the winter of 2000-2001, therelationship between NGLs and natural gas has improved substantially.

On June 6, 2001, Level Propane Gases,Inc. filed suit against MarkWest Hydrocarbon, Inc. in the Court of CommonPleas, Cuyahoga County, Ohio alleging breach of contract for failure to furnisha specified quantity of gallons of propane gas on a monthly basis from May 1,2000 to April 30, 2001, and seeking direct and punitive damages.

On July 25, 2001, MarkWest filed a Motionto stay proceedings pending arbitration in Denver, Colorado in the Court ofCommon Pleas, Coyahoga County, Ohio.

MarkWest believes Level’s breach ofcontract claim has no merit.

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

At the Annual Meeting of Stockholdersheld on June 28, 2001, the following proposals were adopted by the marginsindicated:
1.To  elect three Class II directors to hold office for a three-year term expiring  at the Annual Meeting of Stockholders occurring in the year 2004 or until the  election and qualification of their respective successors.
 
Number of SharesFor Withheld         Brian T. O’Neill7,772,394 6,951 Barry W. Spector7,772,394 6,951 William A. Kellstrom7,772,394 6,951 
 
2.To ratify the  selection of PricewaterhouseCoopers LLP as the Company’s independent  accountants for the fiscal year ending December 31, 2001.
 
 Number  of Shares   For7,772,394 Against0 Abstain0 
**Item 6.  Exhibits andReports on Form 8-K**
(a)Exhibits  11—Statement  regarding computation of earnings per share.  (b)Reports  on Form 8-K  (1)A  report on Form 8-K was filed on August 14, 2001, announcing the acquisition  of two Canadian natural gas production companies.
 

**SIGNATURE**

Pursuant to the requirements of theSecurities Exchange Act of 1934, MarkWest, as registrant, had this reportsigned on our behalf by the undersigned, who has been duly authorized.
 MarkWest  Hydrocarbon, Inc.             (Registrant)      Date:   August 14, 2001By:/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)
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