PART I—FINANCIAL INFORMATION
Item 1.  Consolidated Financial Statements

MARKWEST HYDROCARBON, INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
(000s, except share data)

The accompanying notes are an integral part of these financial statements

MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(UNAUDITED)
(000s, except per share data)

The accompanying notes are an integral part of these financial statements

MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
(000s)

The accompanying notes are an integral part of these financial statements

MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS’ EQUITY
(000s)

The accompanying notes are an integral part of these financial statements

NOTE 1.  GENERAL

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

•            MarkWest Resources, Inc.

•            MarkWest Michigan, Inc.

•            Basin Pipeline, LLC

•            West Shore Processing Company, LLC

•            Matrex, LLC

Through consolidation, we have eliminated all significant intercompany accounts and transactions.

We have prepared the unaudited financial statements presented herein in accordance with the instructions to Form 10-Q.  The statements do not include all the information and note disclosures required by generally accepted accounting principles for complete financial statements.  Please read the interim consolidated financial statements in conjunction with the Consolidated Financial 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 the Securities and Exchange Commission.  In the opinion of management, we have made all necessary adjustments for a fair statement of the results for the unaudited interim periods.  These are only normal recurring adjustments.

We base the effective corporate tax rate for 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 due to tax credits.

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

NOTE 2.  RECENT ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for 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 recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value.  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 Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”).  SFAS 143, is effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for MarkWest), and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets in the period in which they are incurred.  We are in the process of determining the future impact that the adoption of FAS 143 may have on our earnings and financial position.

NOTE 3.   SEGMENT REPORTING

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

We evaluate the performance of our segments and allocate resources to them based on operating income. There are no intersegment revenues.  We conduct our business solely in the United States.  Subsequent to our recent acquisition discussed in Note 6, MarkWest will also be conducting business in Canada.

The table below presents information about operating income for the reported segments for the second quarter of 2001 and 2000 and for the six months ended June 30, 2001 and 2000.  Operating income for each segment includes total revenues less operating expenses and excludes depreciation, depletion and amortization, general and administrative expenses, interest expense, interest income and income taxes.  We have not reported asset information by reportable segment, since we do not produce such information internally.

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

NOTE 4.  CONTINGENCY

In February 2001, three complaints were filed against MarkWest Hydrocarbon, Inc., in the Circuit Court of Wayne County, West Virginia, by Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy LLC; and Cobra Petroleum Company et al.  These complaints 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 in the Denver District Court, Denver, Colorado, against Columbia Gas Transmission Corporation and Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy, LLC; and Cobra Petroleum Production Company et al., to compel arbitration on these matters in accordance with provisions in existing contracts.

NOTE 5.  ADOPTION OF SFAS NO. 133

MarkWest adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, on January 1, 2001.  In accordance with the transition provisions of SFAS 133, we recorded on that date a net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments.

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

SFAS 133 allows hedge accounting for fair-value and cash-flow hedges.  A fair-value hedge applies to a recognized asset or liability or an unrecognized firm commitment.  A cash-flow hedge applies to a forecasted transaction or a variable cash flow of a recognized asset or liability.  SFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair-value hedging instrument as well as the offsetting loss or gain on the hedged item be recognized currently in earnings in the same accounting period.  SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash-flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. (The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.)  Effectiveness is evaluated by the derivative instrument’s ability to generate offsetting changes in fair value or cash flows to the hedged item.  We formally document, designate and assess the effectiveness of transactions receiving hedge accounting treatment.

In our gathering, processing and marketing segment, we enter into fixed-price contracts for the sale of NGLs and fixed-price purchases for the purchase of natural gas and NGLs.  At January 1, 2001, we recorded a risk management asset of approximately $2.1 million in the balance sheet with an offsetting amount recorded, less a deferred tax liability of approximately $0.7 million, in other comprehensive income— approximately $1.3 million gain.  At June 30, 2001, the risk management liability 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 a corresponding risk management asset to reflect our fair value hedges.

In our exploration and production segment, MarkWest enters into fixed-price contracts for the sale of natural gas.  At January 1, 2001, we recorded a risk management liability of approximately $3.9 million in the balance sheet with an offsetting amount recorded, less a deferred tax recovery of approximately $1.4 million, in other comprehensive income—approximately $2.5 million loss.  At June 30, 2001, the risk management asset was $2.0 million, less $0.7 million deferred tax liability, resulting in a $1.3 million gain in other comprehensive income.

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

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

NOTE 6.  SUBSEQUENT EVENT

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

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

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

This Management’s Discussion and Analysis contains statements which, to the extent that they are not recitations of historical fact, constitute “forward-looking statements” 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 as amended (“Section 21E”).  This includes, among other things, statements with respect to the outcome of the pending litigation matters and contract negotiations.  All forward-looking statements involve risks and uncertainties.  We intend that all forward-looking statements in this document are subject to the safe harbor protection provided by Sections 27A and 21E.  Factors that most typically impact MarkWest’s operating results and financial condition include:

Forward-looking statements involve many uncertainties that are beyond our ability to control.  In many cases, we cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements.

Three Months Ended June 30, 2001, Compared to the Three Months Ended June 30, 2000 (in 000s)

The strongest demand for propane, and consequently the highest volumes of and margins for propane sales, generally occur in the winter heating season.  Therefore, a substantial portion of our net income is recognized in the first and fourth quarters.  This seasonality occurs in the GPM segment of our business.

For the quarter ended June 30, 2001, we report 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 same period last year.  Earnings before interest, 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 operations experienced a lower spread between the price of the NGLs versus the cost of the natural 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 gallons versus 32.8 million gallons, down 22 percent from second quarter 2000 to 2001.  This unfavorable volume variance translates to $0.9 million less margin in second quarter 2001.  The decline was due to a longer maintenance shutdown of the Kenova plant to complete an expansion; input pipeline maintenance; weather related shutdowns of producer wells; and delays of additional third-party compression facilities.  Production though is expected to be operating at our newly expanded plant capacities by the end of the third quarter 2001.  Michigan GPM cash operating income was lower by $0.4 million primarily due to the lower volumes in Michigan this year.  The E&P segment was $1.5 million ahead of last year due to the Au Gres well coming on line in July 2000; and in the Rocky Mountain E&P business unit, higher volume and prices as well as the San Juan property acquired earlier this year, improved 2001 results.  Operating expenses as well as the general and administrative expenses were slightly lower in 2001 than the same period last year.

Six Months Ended June 30, 2001, Compared to the Six Months Ended June 30, 2000 (in 000s)

For the six months ended June 30, 2001, we report net income of $1.5 million, or $0.17 per share, compared to net income, excluding gain on sale, of $3.7 million, or $0.44 per share, for the same period last year.  Earnings before interest, taxes and depreciation, depletion and amortization (“EBITDA”) was $6.9 million versus $10.4 million in 2001 and 2000, respectively.

MarkWest’s Appalachian operations experienced a lower spread between the price of the NGLs versus the cost of the natural gas than in the previous year.  The margin was a more normal $0.15 versus an above average $0.21, a difference of $0.06 per gallon, or $2.9 million less margin in 2001.  The $0.15 margin per gallon earned in 2001 is comparable to the ten year average of $0.16 margin per gallon.  Michigan GPM cash operating income was lower by $0.6 million primarily due to the lower volumes in Michigan this year.  The E&P segment was $3.0 million ahead of last year due to the Au Gres well coming on line in July 2000 and in the Rocky Mountain E&P business unit, higher volume and prices, as well as the additional San Juan properties acquired earlier this year improved 2001 results.  Operating expenses as well as the general and administrative costs were higher in 2001 than the same period last year primarily due to increases related to the capital expansions and acquisitions since last year.

Operating data

Gathering, Processing and Marketing  (GPM)

We are paid for our processing in Appalachia through sales of liquids extracted and fees for units of throughput.  A large portion, about 75 percent, of our processing services for gas producers in Appalachia involves extracting NGLs from inlet gas streams and replacing the equivalent heat content with dry natural gas purchased in the spot or forward market.   Consequently, this segment of our business depends on a positive spread between the NGL prices and the cost of the replacement natural gas (“processing margin”).

The operating income for the GPM segment of MarkWest was $2.5 million for the second quarter and almost $7.9 million for year to date 2001.  This compares with $4.5 million for the second quarter of 2000 and $13.5 million for year to date 2000.

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

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

In Western Michigan, our volumes were down 38 percent for the quarter and year to date when compared to the prior year same periods.  Volumes in western Michigan were lower because no new pipeline connections were made and there is a natural depletion in the performance of the existing wells.  This reduced gross margins by $0.5 million compared to the same quarter last year.   The year-to-date throughput volumes are 7,900 Mcfd compared to last year’s throughput volumes of 12,800 Mcfd.  Litigation surrounding another third party well was settled very late in the second quarter 2001 and the additional volumes, currently producing 2,000 Mcfd, will be realized beginning in the third quarter of 2001.  MarkWest, along with industry partners, made two discoveries during second quarter that should provide additional volume in the fourth quarter 2001.  Another large well was recently contracted and is anticipated to be on stream during the fourth 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 for our E&P segment.   Unprecedented high natural gas prices, an acquisition, a new project in eastern Michigan, a second well at Au Gres, and the benefits of our prior year capital investments have all favorably impacted the operating income for this segment.

The operating income for the E&P segment of MarkWest was $1.6 million for the second quarter and $3.5 million year to date 2001.   This compares favorably with $0.3 million for the second quarter of 2000 and $0.6 million for year to date 2000.

The volumes have increased ninety percent or more compared to the prior year volumes.   The acquisition of the Kutz field in the San Juan Basin of New Mexico that closed early this year, a new recompletion well in eastern Michigan, and the infill well drilling and recompletion program initiated last year in the San Juan Basin of Colorado all contributed to the additional volumes this past quarter.  The residual variance is related 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 2000 compared to 2001.  During second quarter, the revenues are $9.0 million lower in 2001 compared to 2000.

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

Appalachia GPM, excluding gas marketing activities previously mentioned, had revenues of  $50.1 million year to date 2001 compared to $42.6 million year to date 2000.  The increase from year to year is predominantly in the product sales price.  The prices have increased from $0.56 per gallon to $0.62 per gallon in 2001.  For the second quarter, revenues are actually lower in 2001 than 2000 by $3.0 million due to fewer sales gallons than last year.

Michigan GPM provided an additional $4.5 million to 2001 revenues compared to 2000 year-to-date revenues with $1.4 million of that additional revenue in the second quarter.  Throughput volumes were down 38 percent during the second quarter and for the year 2001, compared to last year’s volumes.  The decrease in volumes effect on revenues was more than offset by higher prices.  This volume decline is expected to turn around later this year because of new wells being added to the system.  We also chose to deplete on hand inventory in 2001.

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

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

Cost of Sales
Cost of sales has decreased $8.0 million during the second quarter of 2001 compared 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, like revenues, are down $10.2 million in second quarter 2001 compared to 2000.  Gas marketing cost of sales are 56 percent higher than last year at this time, relative to the 57 percent increase in revenues mentioned above.  The gas marketing cost of sales are $16.6 million higher in 2001 than 2000.

Appalachia GPM cost of sales are $10.8 million higher year to date than in year to date 2000.  The predominant cause of this increase is related 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 $5.5 million higher in 2001 than in 2000 with $1.9 million of that occurring in the second quarter 2001.   The volumes were down but the costs were higher per unit this year.

Operating Expenses
Operating expenses increased from $7.9 million year to date 2000 compared to $9.0 million year to date 2001; the second quarter’s operating expenses are $4.0 million in 2000 and 2001.  Much of the increased year-to-date costs relate to the acquisitions and expansions from 2000 being on line for all of 2001 as 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 date 2000 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 cost savings are due to general cost cutting.

Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased year to date by $0.5 million and during the second quarter it increased $0.2 million.  The increase is directly related to the capital expenditures made in 2000 and early in 2001.

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

Liquidity and Capital Resources

MarkWest’s sources of liquidity and capital resources historically have been internal cash flow and our revolving line of credit.  In the first quarter of 2000, we supplemented these sources with proceeds from the sale of our corporate office building.  In the second quarter of 2000, we increased our line of credit by $15 million to $65 million.

The following summary table reflects our comparative cash flows for the six months ended June 30, 2001 and 2000 (in thousands):

Capital Investment Program

MarkWest forecasts a baseline capital budget of $24.5 million in 2001.  In our gathering, processing and marketing segment the 2001 capital budget includes $8 million for completion of Appalachia’s Phase II expansion.  The 2001 capital budget also includes $12 million for our exploration and production segment—$5 million for the acquisition of San Juan Basin properties in 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 expenditures are discretionary and could be reduced depending on capital availability.

Financing Facilities

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

Subsequent Event

See Note 6  SUBSEQUENT EVENT

Commodity Price Risk Management

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

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

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

The use of financial instruments may expose MarkWest to the risk of financial loss in certain circumstances, including instances when (a) sales volumes are less than expected, requiring market purchases to meet commitments; or (b) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs, or crude oil, or otherwise fail to perform.  To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market.  However, we are similarly insulated against decreases in such prices.

MarkWest hedges our basis risk for natural gas, but we are generally unable to do so for NGLs.  Our basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations.  Basis risk is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged.

In our gathering, processing and marketing segment, we hedge Appalachia processing margins by using a combination of methods.  We protect margins by purchasing natural gas priced on predetermined Btu differentials to propane or crude, by simultaneously selling propane or crude oil and purchasing natural gas, and by using swaps.  Crude oil is highly correlated with certain NGL products.  All projected margins on open positions assume the basis differentials between crude oil, and NGLs are consistent with historical averages.  As of June 30, 2001, there are no gallons hedged for processing margin.  Subsequent to June 30, 2001, we have hedged 22.6 million gallons for more than $0.20 per gallon processing margin for the balance of 2001 and 2002.

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

For certain Appalachia natural gas sales, as of June 30, 2001, we have hedged 488,000 and 54,000 MMBtu at $5.19 per MMBtu for 2001 and 2002, respectively.

In addition to these risk management tools, MarkWest utilizes our NGL storage facilities and contracts for third-party storage to build product inventories during historically lower-priced periods for resale during higher-priced periods.  We also have contracts to purchase certain quantities of our natural gas feedstock in advance of physical needs.

In our exploration and production segment, we hedge our exposure to changes in market prices for our natural gas production.  As of June 30, 2001, we had hedged 1,533,000, 908,000, and 632,000 MMBtu of 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 our after-tax earnings compared to the situation of not hedging.  In the gathering, processing and marketing segment, 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 six months ended June 30, 2001 and 2000, respectively.  This impact considers only hedges of Appalachia processing margin and does not reflect other decisions made concerning when to buy natural gas or store NGL production for sale in later months.  In the exploration and production segment, without hedging, net income would 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 on an infrequent basis.  Specific approval by the Board of Directors is necessary prior to executing such transactions.  Speculative transactions are marked to market at the end of each accounting period, and any gain or loss is recognized in income for that period.  There were no such speculative activities for the quarters ended June 30, 2001 and 2000.

Outlook

In the Appalachia GPM segment, we anticipate operating at our new expanded capacity by late in the third quarter 2001.   Phase II of our expansion program is complete which involved building a new plant near our existing facility in Kenova, West Virginia.   Planning for other new projects is well underway that could also have a large positive impact on revenues and ultimately net income.

Michigan GPM has also had some very exciting news this past quarter.  Two new discoveries made with industry partners should greatly improve Michigan volumes in the third and fourth quarter of 2001.   The third party wells that have not been flowing for quite some time have started flowing again and are producing 2,200 Mcfd.  Contract negotiations are complete and we fully expect another third party well to be contributing additional volumes beginning October 2001.  By the end of 2001, the throughput volumes should be more than 20,000 Mcfd, up from the previous estimate of 14,000 Mcfd.

Michigan E&P will be adding a second Au Gres well at the end of July 2001 with production volumes anticipated at 3,500 Mcfd net to MarkWest’s interests.  Current plans provide for the recompletion of a third Au Gres well by the end of 2001.

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

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

With the Canadian acquisition of August 10, 2001, the company added 15,000 Mcfd and 190 barrels of oil per day to MarkWest’s current net production volumes.  The acquisition also added 300 new drillable locations on more than 106,000 acres, with 80 percent considered exploitable.  The wells are relatively shallow, with high initial production and a reserve life of five to seven years.  The future capital expenditures for the next two years is anticipated to be $40 million to provide many additional drillable locations.