CONFORMED COPY

Washington, D.C. 20549

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

the Securities Exchange Act of 1934

For the period ended March 31, 2003

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

the Securities 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: 15,688,333 shares of the Company's Common Stock ($.01 par value) were outstanding as of March 31, 2003.

Indicate by check mark whether the registrant is an accelerated filer (as definition in Rule 12b-2 of the Exchange Act). Yes XX No

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 March 31, 2003, and the related condensed consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These condensed consolidated 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, 2002 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 25, 2003, 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, 2002 is fairly presented, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

KPMG LLP

Pittsburgh, Pennsylvania

May 7, 2003

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

March 31, 2003 and December 31, 2002

(Continued)

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets, Continued

March 31, 2003 and December 31, 2002

See accompanying notes to condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Income

Three Months ended March 31, 2003 and 2002

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

Three Months Ended March 31, 2003 and 2002

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

March 31, 2003

(Unaudited)

1. Accounting Policies

2. Stock Compensation

3. Basis of Presentation

4. Oil and Gas Properties

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5. Earnings Per Share

6. Business Segments (Thousands)

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8. Commitments and Contingencies

9. Common Stock Repurchase

10. Change in Accounting Principle

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

Results of Operations

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Revenues. Total revenues for the three months ended March 31, 2003 were $54.0 million compared to $36.1 million for the three months ended March 31, 2002, an increase of approximately $17.9 million, or 49.6 percent. Such increase was a result of higher gas marketing activities and oil and gas sales from the Company's producing properties. Drilling revenues for the three months ended March 31, 2003 were $21.5 million compared to $21.2 for the three months ended March 31, 2002. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's natural gas marketing subsidiary, for the three months ended March 31, 2003 were $21.6 million compared to $8.5 million for the three months ended March 31, 2002, an increase of approximately $13.1 million or 154.1 percent. Such increase was due to natural gas sold at significantly higher average sales prices offset in part by slightly lower volumes of natural gas marketed. Oil and gas sales from the Company's produ cing properties for the three months ended March 31, 2003 were $8.9 million compared to $4.5 million for the three months ended March 31, 2002, an increase of approximately $4.4 million, or 97.8 percent. The increase was due to significantly higher average sales prices of natural gas and a slight 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, the Company saw a significant strengthening of natural gas prices in its Appalachian and Michigan producing areas. Natural gas prices in Colorado remained low for most of 2002. In the fourth quarter of 2002 and continuing in the first quarter of 2003, Colorado prices began to increase, although they continue to trail prices in other areas. The Company believes the low prices in the Rocky Mountain Region, including Colorado, result from increasing local supplies that exceed the local demand and pipeline capacity available to move gas from the region. On May 1st of 2003, the Kern River pipeline expansion was completed and placed into service. The Kern River Pipeline Company has announced that the additional facilities will add about 900 million cubic feet per day of capacity for deliveries to Arizona, Nevada and southern California. This represents almost 30% of the prior pipeline capacity from the region to the West Coast and other markets outside the region. The Company believes that the completion and start-up of the pipeline will eliminate or reduce the local supply surplus, leading to improved natural gas prices in the region. The Company has commodity price hedging contracts for production from April 2003 through March 2004 to protect against possible short-term price weaknesses. Well operations and pipeline income for the three months ended March 31, 2003 was $1.6 million compared to $1.5 million for the three months ended March 31, 2002, an increase of approximately $100,000 or 6.7 percent. Such increase was due to an increase in the number of wells operated by the Company. Other income for the three months ended March 31, 2003 was $385,000 compared to $415,000 for the three months ended March 31, 2002, a decrease of approximately $30,000.

Costs and expenses. Costs and expenses for the three months ended March 31, 2003 were $46.5 million compared to $31.9 million for the three months ended March 31, 2002, an increase of approximately $14.6 million or 45.8 percent. Oil and gas well drilling operations costs for the three months ended March 31, 2003 were $17.7 million compared to $17.4 million for the three months ended March 31, 2002, an increase of approximately $300,000. The cost of gas marketing activities for the three months ended March 31, 2003 were $21.3 million compared to $8.3 million for the three months ended March 31, 2002, an increase of $13.0 million or 156.6 percent. Such increase was due to the significantly higher average purchase prices of natural gas marketed offset in part by lower volumes purchased for resale. 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 marketing activities during either period. O il and gas production costs from the Company's producing properties for the three months ended March 31, 2003 were $2.9 million compared to $2.1 million for the three months ended March 31, 2002, an increase of approximately $800,000 or 38.1%. Such increase was due to the increased production costs and severance and property taxes on the increased volumes and higher sales volumes of natural gas and oil sold along with the increased number of wells operated by the Company. General and administrative expenses for the three months ended March 31, 2003 increased to $1.2 million compared with $1.0 million for the three months ended March 31, 2002. Depreciation, depletion, and amortization costs for the three months ended March 31, 2003 were $3.2 million compared to $2.9 million for the three months ended March 31, 2002, an increase of approximately $300,000 or 10.3 percent. Such increase was due to the increased amount of production and investment in oil and gas properties owned by the Company. Interest costs fo r the three months ended March 31, 2003 were $237,000 compared to $239,000 for the three months ended March 31, 2002.

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Change in Accounting Principle. The Company adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003 and booked the cumulative effect on prior years of $198,600 (net of taxes of $121,700).

Net income. Net income for the three months ended March 31, 2003 was $4.8 million compared to a net income of $2.9 million for the three months ended March 31, 2002, an increase of approximately $1.9 million or 65.5 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 few years, and the Company anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of gas prices at Henry Hub close to or above record prices per million Btu's (Mmbtu). These prices look strong for the remainder of the year with natural gas storage levels at five-year low levels. The Company believes this situation creates the possibility of both periods of low prices and continued high prices.

Colorado gas prices have been adversely affected by an increase in the negative "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 during the summer months. Higher winter demand by local Rocky Mountain markets improved gas prices during the first quarter, and the recent start-up of the Kern River Pipeline expansion project should help to correct this problem in the coming months. Several other 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 to be better in the remainder of 2003 than it was in 2002.

Because of the uncertainty surrounding natural gas prices we have used various hedging instruments to manage some of the impact of fluctuations in prices. Through March of 2004 we have in place a series of floors and ceilings on part of our natural gas production. Under the 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. The positions in effect as of March 31, 2003 on the Company's share of production are shown in the following table:

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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 softened 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 the Company's production reflected by oil sales has increased to 17%, variations in oil prices will have a greater impact on the Company than in the past. The Company also has in place as of March 31, 2003 hedges on 4,800 barrels a month for its Wattenburg Field oil production for the period from April 2003 through March 2004 at a price of $30.00 per barrel.

The Company plans to conduct most, if not all, of its 2003 drilling operations in Colorado. If future 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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The Company has commenced sales of units in its ninth partnership in its registered PDC 2003 public drilling program which has four remaining partnerships which are scheduled to close during 2003. The ninth partnership is scheduled to close in the second quarter of 2003, with drilling planned in the second and third quarters of 2003. Additional programs are scheduled to close in September, November and December of 2003. 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 $2,434,900. The Company has adequate liquidity to meet this obligation.

On March 13, 2003 the Company publicly announced a common stock repurchase program to repurchase up to 5% of the Company's outstanding common stock (785,000 shares) expiring on December 31, 2004. From inception of the program until March 31, 2003, the Company has repurchased 46,500 shares at an average price of $6.02 per share. The Company intends to fund this repurchase of common stock through internally generated cash flow.

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, of which the Company has activated $40.0 million of the facility. As of March 31, 2003, the outstanding balance on the line of credit was $23.0 million of which $10.0 million was subject to an interest rate swap at a rate of 8.39% and the remaining $13.0 million was subject to a prime rate of 4.25%. The line of credit is at prime, with LIBOR alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on July 3, 2005.

A summary of Company's contractual obligations and due dates are as follows:

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.

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:

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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 the 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 carry-forwards, and credit carry-forwards 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.

New Accounting Standards

In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure, an amendment of FASB Statement No. 123. This statement amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for interim periods beginning after ending December 15, 2002 and are included in the notes to these condensed financial statements.

Item 3. Quantitative and Qualitative 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, 2002.

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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 March 31, 2003, PDC had entered into a series of natural gas future contracts and options contracts. The fair value of these f loors and ceilings as of March 31, 2003 is ($512,800). Open future contracts maturing in 2003-2005 are for the sale of 4,970,000 Mmbtu of natural gas with a weighted average price of $4.36 Mmbtu resulting in a total contract amount of $21,644,400, and a fair market value of $(2,800,800). Open option contracts are for the sale of 1,610,280 Mmbtu of natural gas with an average ceiling price of $4.86 and for the sale of 3,235,680 Mmbtu of natural gas with an average floor price of $3.88 and a fair market value of ($512,800).

Item 4. Controls and Procedures

Under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, the Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) within 90 days of the filing date of this quarterly report, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

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) Exhibits

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(b) Report on Form 8-K during the quarter ended March 31, 2003

Form 8-K current report dated January 24, 2003, under Item 5. "Other Matters" the Board of Directors accepted the resignation of Roger J. Morgan as a Director. Mr. Morgan will remain Secretary of the Corporation. On recommendation of the Nominating Committee, the Board of Directors named Kimberly Luff Wakim to fill the unexpired term of Mr. Morgan as Director. The Board of Directors adopted revisions to the corporations By-laws.

Form 8-K current report dated February 27, 2003, under Item 5. "Other Matters" the Company issued a news release announcing the fourth quarter and 2002 operating results.

Form 8-K current report dated March 12, 2003, under Item 5. "Other Matters" the Company issued a news release announcing the planned retirement of CEO and Chairman James N. Ryan.

Form 8-K current report dated March 14, 2003, under Item 5. "Other Matters" the Company issued a news release announcing a stock repurchase plan.

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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FORM 10-Q CERTIFICATION

I, James N. Ryan , certify that:

1. I have reviewed this quarterly report on Form 10-Q of Petroleum Development Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report.
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

1. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: _May 7, 2003

/s/ James N. Ryan