CONFORMED COPY

Washington, D.C. 20549

[X] Quarterly Report Pursuant to Section 13 or 15(d) of

the Securities and Exchange Act of 1934

For the period ended June 30, 2002

[ ] Transition Report Pursuant to Section 13 of 15(d) of

the Securities and Exchange Act of 1934

For the transition period from to

Commission file number 0-7246

I.R.S. Employer Identification Number 95-2636730

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for 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 XX No

Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date: 15,734,767 shares of the Company's Common Stock ($.01 par value) were outstanding as of June 30, 2002.

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

INDEX

PART I - FINANCIAL INFORMATION

The Board of Directors

Petroleum Development Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Petroleum Development Corporation and subsidiaries as of June 30, 2002, and the related condensed consolidated statements of income and cash flows for the three-month and six-month periods ended June 30, 2002 and 2001. These financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical review procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of Petroleum Development Corporation and subsidiaries as of December 31, 2001 and the related consolidated statements of income, stockholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 27, 2002, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2001 is fairly presented, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

KPMG LLP

Pittsburgh, Pennsylvania

August 2, 2002

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

June 30, 2002 and December 31, 2001

(Continued)

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets, Continued

June 30, 2002 and December 31, 2001

See accompanying notes to condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Income

Three Months and Six Months ended June 30, 2002 and 2001

(Unaudited)

See accompanying notes to condensed consolidated financial statements

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

Six Months Ended June 30, 2002 and 2001

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

June 30, 2002

(Unaudited)

1. Accounting Policies

2. Basis of Presentation

3. Oil and Gas Properties

4. Earnings Per Share

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5. Business Segments (Thousands)

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6. Comprehensive Income

7. Common Stock

8. Commitments and Contingencies

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9. Subsequent Event

On July 3, 2002, the Company executed a $100 million credit facility with Bank One, NA and BNP Paribas. The agreement converts the credit facility to a syndicated arrangement structured for growth and provides for borrowing up to $100 million subject to and secured by adequate levels of oil and gas reserves.

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

Revenues. Total revenues for the three months ended June 30, 2002 were $33.5 million compared to $47.1 million for the three months ended June 30, 2001, a decrease of approximately $13.6 million, or 28.9 percent. Such decrease was primarily a result of reduced drilling revenues and gas marketing activities. Drilling revenues for the three months ended June 30, 2002 were $13.3 million compared to $21.8 million for the three months ended June 30, 2001 a decrease of approximately $8.5 million, or 39.0 percent. The decrease was a result of higher than normal drilling activity carried over from the Company's public drilling programs at the end of 2000. The wells were drilled and completed during the first half of 2001. The carryover resulted from a shortage of drilling rigs and field services during the second half of 2000 which delayed the drilling and completion of the wells which normally would have been drilled during the second half of 2000. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the three months ended June 30, 2002 were $12.0 million compared to $16.9 million for the three months ended June 30, 2001, a decrease of approximately $4.9 million or 29.0 percent. Such decrease was due to natural gas sold at lower average sales prices along with slightly lower volumes sold. Oil and gas sales from the Company's producing properties for the three months ended June 30, 2002 were $6.4 million compared to $6.5 million for the three months ended June 30, 2001, a decrease of approximately $100,000. Such decrease was due to lower average sales prices of natural gas offset in part by an increase in volumes produced of natural gas and oil from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. Natural gas prices declined dramatically at the end of the fourth quarter 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, we saw a significant strengthening and expect stronger prices later in the year, particularly as winter begins. During the second quarter of 2002, we have entered into some commodity price hedging contracts for production from May 2002 through March 2003 to protect ourselves against possible short-term price weaknesses. Well operations and pipeline income for the three months ended June 30, 2002 was $1.4 million compared to approximately $1.4 million for the three months ended June 30, 2001. Other income for the three months ended June 30, 2002 was $468,000 compared to $516,000 for the three months ended June 30, 2001.

Costs and expenses. Costs and expenses for the three months ended June 30, 2002 were $30.0 million compared to $41.7 million for the three months ended June 30, 2001, a decrease of approximately $11.7 million or 28.1 percent. Oil and gas well drilling operations costs for the three months ended June 30, 2002 were $11.2 million compared to $18.9 million for the three months ended June 30, 2001, a decrease of approximately $7.7 million or 40.7 percent. Such decrease was due to the reduced drilling activity referred to above. The cost of gas marketing activities for the three months ended June 30, 2002 were $12.2 million compared to $17.1 million for the three months ended June 30, 2001, a decrease of $4.9 million or 28.7 percent. Such decrease was due to reduced volumes purchased at lower average sales prices of natural gas marketed. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net margins from marke ting activities during either period.

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Oil and gas production costs from the Company's producing properties for the three months ended June 30, 2002 were $2.2 million compared to $2.5 million for the three months ended June 30, 2001, a decrease of approximately $300,000 or 12.0 percent. General and administrative expenses for the three months ended June 30, 2002 remained constant at approximately $1.0 million as compared to the three months ended June 30, 2001. Depreciation, depletion, and amortization costs for the three months ended June 30, 2002 were $3.1 million compared to $2.0 million for the three months ended June 30, 2001, an increase of approximately $1.1 million or 55.0 percent. Such increase was due to the increased amount of investment in oil and gas properties owned by the Company, principally during the second half of 2001. Interest costs for the three months ended June 30, 2002 were $356,000 compared to $214,000 for the three months ended June 30, 2001, an increase of approximately $142,000. The increase was d ue to higher average outstanding balances offset in part by lower interest rates on the Company's credit facility.

Net income. Net income for the three months ended June 30, 2002 was $2.4 million compared to a net income of $3.8 million for the three months ended June 30, 2001, a decrease of approximately $1.4 million or 36.8 percent.

Revenues. Total revenues for the six months ended June 30, 2002 were $69.6 million compared to $106.7 million for the six months ended June 30, 2001, a decrease of approximately $37.1 million, or 34.8 percent. Such decrease was primarily a result of reduced drilling revenues, gas marketing activities and oil and gas sales. Drilling revenues for the six months ended June 30, 2002 were $34.4 million compared to $43.2 million for the six months ended June 30, 2001 a decrease of approximately $8.8 million, or 20.4 percent. The decrease was a result of higher than normal drilling activity carried over from the Company's public drilling programs at the end of 2000. The wells were drilled and completed during the first half of 2001. The carryover resulted from a shortage of drilling rigs and field services during the second half of 2000 which delayed the drilling and completion of the wells which normally would have been drilled during the second half of 2000. Natural gas sales from t he marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the six months ended June 30, 2002 were $20.4 million compared to $45.7 million for the six months ended June 30, 2001, a decrease of approximately $25.3 million or 55.4 percent. Such decrease was due to natural gas sold at significantly lower average sales prices along with slightly lower volumes sold. Oil and gas sales from the Company's producing properties for the six months ended June 30, 2002 were $10.9 million compared to $14.0 million for the six months ended June 30, 2001, a decrease of approximately $3.1 million or 22.1 percent. Such decrease was due to lower average sales prices of natural gas offset in part by an increase in volumes produced and sold of natural gas and oil from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas mar ket has remained prevalent in the last few years. Natural gas prices declined dramatically at the end of the fourth quarter 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, the Company saw a significant strengthening and expect stronger prices later in the year, particularly as winter begins. During the second quarter of 2002, the Company has entered into some commodity price hedging contracts for production from May 2002 through March 2003 to protect ourselves against possible short-term price weaknesses. Well operations and pipeline income for the six months ended June 30, 2002 was $2.9 million compared to approximately $2.7 million for the six months ended June 30, 2001 an increase of $200,000 or 7.4 percent . Such increase was due to an increase in the number of wells operated by the Company. Other income for the six months ended June 30, 2002 was $883,000 compared to $973,000 for the six months ended June 30, 2001.

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Costs and expenses. Costs and expenses for the six months ended June 30, 2002 were $61.8 million compared to $93.2 million for the six months ended June 30, 2001, a decrease of approximately $31.4 million or 33.7 percent. Oil and gas well drilling operations costs for the six months ended June 30, 2002 were $28.6 million compared to $37.4 million for the six months ended June 30, 2001, a decrease of approximately $8.8 million or 23.5 percent. Such decrease was due to the reduced drilling activity referred to above. The cost of gas marketing activities for the six months ended June 30, 2002 were $20.4 million compared to $45.3 million for the six months ended June 30, 2001, a decrease of $24.9 million or 55.0 percent. Such decrease was due to reduced volumes purchased at significantly lower average sales prices of natural gas marketed. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net margins from ma rketing activities during either period. Oil and gas production costs from the Company's producing properties for the six months ended June 30, 2002 were $4.3 million compared to $4.2 million for the six months ended June 30, 2001, an increase of approximately $100,000 or 2.3 percent. General and administrative expenses for the six months ended June 30, 2002 remained constant at approximately $2.0 million as compared to the six months ended June 30, 2001. Depreciation, depletion, and amortization costs for the six months ended June 30, 2002 were $6.0 million compared to $4.0 million for the six months ended June 30, 2001, an increase of approximately $2.0 million or 50.0 percent. Such increase was due to the increased amount of investment in oil and gas properties owned by the Company, principally in the second half of 2001. Interest costs for the six months ended June 30, 2002 were $595,000 compared to $428,000 for the six months ended June 30, 2001, an increase of approximately $167,000. The increase wa s due to higher average outstanding balances offset in part by lower interest rates on the Company's credit facility.

Net income. Net income for the six months ended June 30, 2002 was $5.4 million compared to a net income of $9.4 million for the six months ended June 30, 2001, a decrease of approximately $4.0 million or 42.6 percent.

The Company funds its operations through a combination of cash flow from operations, capital raised through drilling partnerships, and use of the Company's credit facility. Operational cash flow is generated by sales of natural gas from the Company's well interests, well drilling and operating activities for the Company's investor partners, natural gas gathering and transportation, and natural gas marketing. Cash payments from Company-sponsored partnerships are used to drill and complete wells for the partnerships, with operating cash flow accruing to the Company to the extent payments exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash flow requirements of its operating and investment activities.

Natural gas and oil prices have been unusually volatile for the past 24 months, and the Company anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of gas prices close to or above $3 per million Btu's (mmbtu) for the balance of 2002 and even higher beyond the end of the year. This price level apparently reflects market concern about the adequacy of natural gas deliverability given a normal winter and/or a recovery of the economy. In contrast natural gas storage levels are at historically high levels, a situation that in the past has resulted in low gas prices. The Company believes this situation creates the possibility of both periods of low prices and of significantly higher prices.

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This spring and summer, our Colorado gas prices have been adversely effected by an increase in the "basis" between NYMEX and Colorado prices. Pipeline capacity from the area to major markets in California and the Midwest is not adequate to move the new supplies developed over the past several years by oil and gas companies when local demand is at low summer levels. The result has been lower prices and some limited curtailment of production. Several major pipeline projects are underway and in planning stages that will improve capacity over the next several years. There remains a possibility of greater seasonal volatility in Colorado than some other producing areas, but we expect the situation to improve over the coming year.

Because of the uncertainty surrounding gas prices we used hedging agreements to reduce some of the impact of fluctuations in prices. Through March of 2003 we have in place a series of costless collars. Under the collar arrangements, if the applicable index rises above the ceiling price, we pay the counterparty, however if the index drops below the floor the counterparty pays us. These floor and ceiling prices were set at levels which allowed us to set floors on two units of production for each unit of production with a ceiling. The positions currently in effect on the Company's share of production are shown in the following table:

The Company hedges prices for its partners' share of production as well as its own production. Actual wellhead prices will vary based on local contract conditions, gathering and other costs and factors.

Oil prices have strengthened from earlier in the year. While oil prices are influenced by supply and demand, global geopolitics may be the single most important determinant. Since the percentage of company production reflected by oil sales has increased to almost 19% for the first half of 2002, variations in oil prices will have a greater impact on the Company than in the past.

The Company plans to conduct most, if not all, of its 2002 drilling operations in Colorado. If the planned pipeline capacity increases do not occur, it could reduce the Company's results from its producing activities. It could also make the company's drilling programs less attractive to potential investors. However, the Rocky Mountain region is the only onshore area of the U.S. with increasing production. The company believes the necessary pipelines will be constructed, so increasing Rocky Mountain gas can move to the markets where it will be needed.

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Oil and gas drilling revenues are generated primarily by sales of company-sponsored partnerships. The number of NASD broker-dealer firms has increased this year to 140 from 110 in 2001. Sales of partnership interests, however, are down from the record levels of 2001, although still ahead of prior years. The Company believes the decline is largely attributable to lower natural gas prices, which were at record levels in 2001 and substantially lower in 2002. In addition, the recession and stock market collapse have probably reduced the dollars available for investment generally, and led some investors with available funds to defer investing until the market shows signs of recovery.

As a result of these factors and others, it is impossible to predict future levels of drilling fund sales and drilling revenue. Based on sales to date, the Company anticipates an investment level below the 2001 record, but at or above the previous year's.

The Company closed its first drilling program of 2002 in the second quarter and has drilled the wells in the second and third quarters of 2002. This program closed with investor subscriptions of $7.1 million. The Company will close its second drilling program of 2002 in September, 2002 and will drill the wells during the third and fourth quarters of 2002. Additional programs are scheduled to close in November and December of 2002. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. No assurance can be made that the Company will continue to receive this level of funding from these or future programs.

Substantially all of the Company's drilling programs contain a repurchase provision where Investors may tender their partnership units for repurchase at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such units are tendered, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if tendered by the investors, is currently approximately $2,208,500. The Company has adequate liquidity to meet this obligation.

The Company has a credit facility with Bank One, NA and BNP Paribas of $100 million subject to adequate oil and natural gas reserves. The current borrowing base is $58.0 million. As of June 30, 2002, the outstanding balance was $26.7 million. Interest accrues at prime, with LIBOR (London Interbank Market Rate) alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on December 31, 2004.

The Company continues to pursue capital investment opportunities in producing natural gas properties as well as its plan to participate in its sponsored natural gas drilling partnerships, while pursuing opportunities for operating improvements and costs efficiencies. Management believes that the Company has adequate capital to meet its operating requirements.

A summary of Company's debt and lease obligations and commitments as of June 30, 2002 are as follows:

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Critical Accounting Policies

Certain accounting policies are very important to the portrayal of Company's financial condition and results of operations and require management's most subjective or complex judgments. The policies are as follows:

Revenue Recognition

     Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress.

     Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank.

     Well operations income consists of operation charges for well upkeep, maintenance and operating lease income on tangible well equipment.

Valuation of Accounts Receivable

     Management reviews accounts receivable to determine which are doubtful of collection. In making the determination of the appropriate allowance for doubtful accounts, management considers Company's history of write-offs, relationships and overall credit worthiness of its customers, and well production data for receivables related to well operations.

Impairment of Long-Lived Assets

     Exploration and development costs are accounted for by the successful efforts method.

     The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

     Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred.

Deferred Tax Asset Valuation Allowance

     Deferred tax assets are recognized for deductible temporary differences, net operating loss carryforwards, and credit carryforwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset cannot be recognized under the preceding criteria, a valuation allowance has been established.

     The judgments used in applying the above policies are based on management's evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. See additional discussions in this Management's Discussion and Analysis.

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     In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company also records a corresponding asset which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. At this time, the Company cannot reasonably estimate the effect of the adoption of this Statement on either its financial position, results of operations, o r cash flows.

Item 3. Quantitative and Qualititive Disclosure About Market Rate Risk

Interest Rate Risk

There have been no material changes in the reported market risks faced by the Company since December 31, 2001.

Commodity Price Risk

The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures contracts and option contracts. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Company will receive for the volume to which the hedge relates. As a result, while these hedging arrangements are structured to reduce the Company's exposure to decreases in price associated with the hedging commodity, they also limit the benefit the Company might otherwise have received from price increases associated with the hedged commodity. The Company's policy prohibits the use of natural gas future and option contracts for speculative purposes. As of June 30, 2002, PDC had entered into a series of natural gas future contracts and options contracts. Through March of 2003 the Company has in place a series of costless collars. Under the collar arrangements, if the applicable index rises above the ceiling price, the Company pays the counterparty, however if the index drops below the floor the counterparty pays the Company. These floors and ceiling prices were set at levels which allowed the Company to set floors on two units of production for each unit of production with a ceiling. For the period from July 2002 to October 2002 the Company has floors in place in a range of from $2.20 to $2.85 on 261,500 Mmbtu of monthly production and ceilings in place in a range from $3.20 to $3.75 on 130,800 Mmbtu of monthly production. For the period from November 2002 through March 2003, the Company has floors in place in a range from $2.75 to $3.70 on 142,000 Mmbtu of monthly production and ceilings in place in a range from $3.75 to $4.45 on 71,000 Mmbtu of monthly production. The fair value of these floors and ceilings as of June 30, 2002 is $88,100. Open future contracts maturing in 2002 are for the sale of 1,650,000 dt of natural gas with a weighted average price of $3.46 dt resulting in a total contract amount of $5,714,600, and a fair market value of $(81,300).

Open option contracts are for the sale of 660,100 dt of natural gas with an average ceiling price of $3.88 and for the sale of 1,320,200 dt of natural gas with an average floor price of $3.12.

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CONFORMED COPY

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The Company is not a party to any legal actions that would materially affect the Company's operations or financial statements.

Item 6. Exhibits and Reports on Form 8-K

(a) None.

(b) No reports on Form 8-K have been filed during the quarter ended June 30, 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934 the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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