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 September 30, 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: 15,628,433 shares of the Company's Common Stock ($.01 par value) were outstanding as of September 30, 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 September 30, 2003, the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2003 and 2002, and the related condensed consolidated statements of cash flows for the nine-month periods ended September 30, 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 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.

KPMG LLP

Pittsburgh, Pennsylvania

October 30, 2003

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

September 30, 2003 and December 31, 2002

(Continued)

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets, Continued

September 30, 2003 and December 31, 2002

See accompanying notes to unaudited condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Income

Three Months and Nine Months ended September 30, 2003 and 2002

(Unaudited)

See accompanying notes to unaudited condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2003 and 2002

(Unaudited)

See accompanying notes to unaudited condensed consolidated financial statements.

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

September 30, 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

11. Acquisition of Oil and Gas Properties

12. Subsequent Event - Commitments and Contingencies

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

Results of Operations

Revenues. Total revenues for the three months ended September 30, 2003 were $47.2 million compared to $28.1 million for the three months ended September 30, 2002, an increase of approximately $19.1 million, or 68.0 percent. Such increase was a result of increased drilling revenues, sales from gas marketing activities, oil and gas sales and well operations and pipeline income. Drilling revenues for the three months ended September 30, 2003 were $14.1 million compared to $9.4 million for the three months ended September 30, 2002, an increase of approximately $4.7 million or 50.0 percent. Such increase was due to the drilling backlog at June 30, 2003 along with the early closing of the fully subscribed PDC 2003-B Partnership. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the three months ended September 30, 2003 were $17.7 million compared to $11.7 million for the three months ended September 30, 2002, an increas e of approximately $6.0 million or 51.3 percent. Such increase was due to natural gas sold at higher average sales prices offset in part by lower volumes sold. Oil and gas sales from the Company's producing properties for the three months ended September 30, 2003 were $13.1 million compared to $5.1 million for the three months ended September 30, 2002, an increase of $8.0 million or 156.9 percent. The increase was due to significantly increased volumes sold at substantially higher average sales prices of oil and natural gas. The volume of natural gas sold for the three months ended September 30, 2003 was 2.4 million Mcf at an average sales price of $4.55 per Mcf compared to 1.6 million Mcf at an average sales price of $2.35 per Mcf for the three months ended September 30, 2002. Oil sales were 80,000 barrels at an average sales price of $28.42 per barrel for the three months ended September 30, 2003 compared to 51,000 barrels at an average sales price of $26.39 per barrel for the three months ended September 30, 2002. The increase in natural gas volumes was the result of the Company's increased investment in oil and gas properties, primarily the Williams property acquisition, effective April 1, 2003, recompletions of existing wells and the Company's additional investment in wells drilled along with the PDC

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2003-A Partnership. 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 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 2003, Colorado prices began to increase, although they continue to trail prices in other areas. The Company believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded the local demand and pipeline capacity available to move gas from the region. On May 1st of 2003, the Kern River pipeline expansio n was completed and placed into service. The Kern River Pipeline Company has announced that the additional facilities added 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 eliminated or reduced the local supply surplus, leading to improved natural gas prices in the region. Since the startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from 83% to over 90% of the NYMEX price, levels consistent with historical price relationships before the recent local demand/pipeline capacity problem. The Company has commodity price hedging contracts for production from October 2003 through December 2004 to protect against possible short-term price weaknesses.

Well operations and pipeline income for the three months ended September 30, 2003 was $1.9 million compared to $1.5 million for the three months ended September 30, 2002, an increase of approximately $400,000 or 26.7 percent. Such increase was due to an increase in the number of wells and pipelines operated by the Company. Other income for the three months ended September 30, 2003 was $488,000 compared to $451,000 for the three months ended September 30, 2002.

Production by area of operations:

Costs and expenses. Costs and expenses for the three months ended September 30, 2003 were $39.4 million compared to $27.0 million for the three months ended September 30, 2002, an increase of approximately $12.4 million or 45.9 percent. Such increase was primarily the result of increased cost of oil and gas well drilling operations, gas purchased for gas marketing activities, and oil and gas production costs. Oil and gas well drilling operations costs for the three months ended September 30, 2003 were $12.0 million compared to $8.5 million for the three months ended September 30, 2002, an increase of approximately $3.5 million or 41.1 percent. Such increase was due to the higher levels of drilling referred to above. The cost of gas marketing activities for the three months ended September 30, 2003 were $17.5 million compared to $11.7 million for the three months ended September 30, 2002, an increase of $5.8 million or 49.6 percent. The increase was due to the significantly higher average prices of natural gas purchased and offset in part by slightly lower volumes. 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. Oil and gas production costs from the Company's producing properties for the three months ended September 30, 2003 were $4.0 million compared to $2.2 million for the three months ended September 30, 2002, an increase of approximately $1.8 million or 81.8% percent. Such increase was due to the increased production costs and severance and property taxes on the increased volumes and higher sales prices of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. General and administrative expenses for the three months ended September 30, 2003 increased to $1.4 million compared with $1.1 million for the three months ended September 30, 2002.

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Depreciation, depletion, and amortization costs for the three months ended September 30, 2003 increased to $4.2 million from approximately $3.1 million for the three months ended September 30, 2002. The increase was due to the significantly increased production and investment in oil and gas properties by the Company as referred to above. Interest costs for the three months ended September 30, 2003 were $415,000 compared to $400,000 for the three months ended September 30, 2002.

Net income. Net income for the three months ended September 30, 2003 was $5.2 million compared to a net income of $900,000 for the three months ended September 30, 2002, an increase of approximately $4.3 million.

Revenues. Total revenues for the nine months ended September 30, 2003 were $143.4 million compared to $97.7 million for the nine months ended September 30, 2002, an increase of approximately $45.7 million, or 46.8 percent. Such increase was a result of increased drilling revenues, sales from gas marketing activities, oil and gas sales and well operations and pipeline income. Drilling revenues for the nine months ended September 30, 2003 were $47.4 million compared to $43.8 million for the nine months ended September 30, 2002, an increase of approximately $3.6 million or 8.2 percent. Such increase was due to increased volume of drilling activity by the Company's drilling programs. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the nine months ended September 30, 2003 were $56.6 million compared to $32.1 million for the nine months ended September 30, 2002, an increase of approximately $24.5 million or 76.3 perce nt. Such increase was due to natural gas sold at significantly higher average sales prices offset in part by lower volumes sold. Oil and gas sales from the Company's producing properties for the nine months ended September 30, 2003 were $32.9 million compared to $16.0 million for the nine months ended September 30, 2002, an increase of $16.9 million or 105.6 percent. The increase was due to significantly increased volumes sold at substantially higher average sales prices of oil and natural gas. The volume of natural gas sold for the nine months ended September 30, 2003 was 6.1 million Mcf at an average sales price of $4.46 per Mcf compared to 4.8 million Mcf at an average sales price of $2.49 per Mcf for the nine months ended September 30, 2002. Oil sales were 195,000 barrels at an average sales price of $28.05 per barrel for the nine months ended September 30, 2002 compared to 175,000 barrels at an average sales price of $22.89 per barrel for the nine months ended September 30, 2002. The increase in natural gas volumes was the result of the Company's increased investment in oil and gas properties, primarily the Williams property acquisition, effective April 1, 2003, recompletions of existing wells and the Company's additional investment in wells drilled along with the PDC 2003-A Partnership. 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 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 2003, Colorado prices began to increase, although they continue to trail prices in other areas. The Company believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded 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 added 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 eliminated or reduced the local supply surplus, leading to improved natural gas prices in the region. Since startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from 83% to over 90% of the NYMEX price, levels consistent with historical price relationships before the recent local demand /pipeline capacity problem. The Company has commodity price hedging contracts for production from October 2003 through December 2004 to protect against possible short-term price weaknesses.

Well operations and pipeline income for the nine months ended September 30, 2003 was $5.3 million compared to $4.4 million for the nine months ended September 30, 2002, an increase of approximately $900,000 or 20.5 percent. Such increase was due to an increase in the number of wells and pipelines operated by the Company. Other income for the nine months ended September 30, 2003 was $1.2 million compared to $1.3 million for the nine months ended September 30, 2002.

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Production by area of operations:

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Costs and expenses. Costs and expenses for the nine months ended September 30, 2003 were $121.3 million compared to $88.9 million for the nine months ended September 30, 2002, an increase of approximately $32.4 million or 36.4 percent. Such increase was primarily the result of increased cost of oil and gas well drilling operations, gas purchased for gas marketing activities and oil and gas production costs. Oil and gas well drilling operations costs for the nine months ended September 30, 2003 were $39.8 million compared to $37.1 million for the nine months ended September 30, 2002, an increase of approximately $2.7 million or 7.3 percent. Such increase was due to the higher levels of drilling volumes referred to above. The cost of gas marketing activities for the nine months ended September 30, 2003 were $55.9 million compared to $32.2 million for the nine months ended September 30, 2002, an increase of $23.7 million or 73.6 percent. The increase was due to the significantly h igher average purchase prices of natural gas purchased and marketed offset in part by slightly 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. Oil and gas production costs from the Company's producing properties for the nine months ended September 30, 2003 were $10.3 million compared to $6.4 million for the nine months ended September 30, 2002, an increase of approximately $3.9 million or 60.9 percent. Such increase was due to the increased production costs and severance and property taxes on the significantly increased volumes and higher average sales prices of natural gas and oil sold along with the increased number of wells and pipelines operated by the Company. General and administrative expenses for the nine months ended September 30, 2003 increased to $3.7 million compared with $3.1 million for the nine months ended September 30, 2002 an increase of approximately $600,000 or 19.4 percent. Depreciation, depletion, and amortization costs for the nine months ended September 30, 2003 increased to $10.6 million from approximately $9.1 million for the nine months ended September 30, 2002 an increase of approximately $1.5 million or 16.5 percent. . The increase was due to the significantly increased production and investment in oil and gas properties by the Company as referred to above. Interest costs for the nine months ended September 30, 2003 were $911,000 compared to $995,000 for the nine months ended September 30, 2002.

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 nine months ended September 30, 2003 was $14.6 million compared to a net income of $6.2 million for the nine months ended September 30, 2002, an increase of approximately $8.4 million or 135.5 percent.

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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 although natural gas storage levels are near normal levels following a period when storage levels had been at a five-year low. The Company believes this situation creates the possibility of both periods of low prices and continued high prices.

In 2001, 2002 and earlier this year Colorado gas prices were adversely affected by an increase in the negative "basis" between NYMEX and Colorado prices. In the past, natural gas produced by the Company in Colorado has sold for 10-20% less than the Company's prices received in the Michigan and Appalachian basins, but the Company's Colorado development costs have been less than the costs per Mcfe of development in the Michigan and Appalachian basins. Pipeline capacity from the area to major markets in California and the Midwest was not adequate to move the new supplies developed over the past several years by oil and gas companies when local demand was at low summer levels. The result was 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 three quarters of 2003, and the recent start-up of the Kern River Pipeline expansion project has reduced the price dis count to historical levels. 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 continue to be better for 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 December 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. During the three months ended September 30, 2003 the Company averaged natural gas volumes sold of 792,700 Mcf per month and oil sales of 26,700 barrels per month. The positions in effect as of September 30, 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. Only the Company's share of hedging is reflected in the proceeding table and in this narrative. 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 September 30, 2003 hedges on 4,800 barrels a month for its Wattenburg Field oil production for the period from October 2003 through December 2003 at a price of $30.00 per barrel.

The Company plans to conduct 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.

The Company closed its second drilling program of 2003 in September, 2003 and started the drilling of the wells during the third quarter with the remainder to be drilled in the fourth quarter 2003. This second drilling program of 2003 closed early after being fully subscribed with subscriptions of $17.5 million compared to the second program of 2002 which closed with subscriptions of $11.2 million. The third drilling program of 2003 the PDC 2003-C Partnership will close early during the first week of November at the maximum investor subscriptions of $17.5 million compared with the third program of 2002 which closed with subscriptions of $9.4 million. The fourth drilling program of 2003 the PDC 2003-D is scheduled to close on December 31, 2003 and has a maximum allowable subscriptions of $35 million. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum of 21.75% of the aggregate subscriptions received for that particular drilling partner ship. 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 request the Company to repurchase their partnership units 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 investors request the Company to repurchase such units subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if requested by the investors, is currently approximately $4.2 million. The Company has adequate liquidity to meet this obligation. During 2003 the Company has spent $200,600 under this provision.

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 September 30, 2003, the Company has repurchased 109,200 shares at an average price of $7.90 per share. The Company intends to fund this repurchase of common stock through internally generated cash flow.

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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 $80.0 million, of which the Company has activated $50.0 million of the facility. As of September 30, 2003, the outstanding balance on the line of credit was $46.0 million of which $10.0 million was subject to an interest rate swap at a rate of 8.39% , $24.0 million at a LIBOR rate of 2.62% and the remaining $12.0 million was subject to a prime rate of 4.00%. 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:

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.

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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.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS no. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs mineral rights associated with extracting oil and gas intangible assets in the balance sheets, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify the historical cost of approximately $5,169,000 and $4,208,800 of mineral rights associated with undeveloped oil and gas properties and $12,335,900 and $10,898,700 of mineral rights associated with developed oil and gas properties as of September 30, 2003 and December 31, 2002, respectively, out of oil and gas properties and into a separate intangible mineral rights assets line item. The Company's total balance sheet, cash flows and results of operations would be not affected since such intangible assets would continue to be amortized and assessed for impairment.

The reclassification of these amounts would not affect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a result, net income would not be affected by the reclassification.

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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.

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 and Colorado Interstate-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 September 30, 2003, PDC had entered into a series of natural gas future contracts and options contract s. The fair value of these floors and ceilings as of September 30, 2003 is ($24,500). Open future contracts maturing in 2003-2005 are for the sale of 2,790,000 Mmbtu of natural gas with a weighted average price of $4.43 Mmbtu resulting in a total contract amount of $12,361,500, and a fair market value of $(1,046,100). Open option contracts are for the sale of 400,800 Mmbtu of natural gas with an average ceiling price of $5.18 and for the sale of 2,946,900 Mmbtu of natural gas with an average floor price of $4.40 and a fair market value of ($24,500).

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)) as of the end of this fiscal quarter, 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 c hanges in our internal control over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect these controls that occurred during the Company's last fiscal quarter.

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.

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Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

(b) Reports on Form 8-K during the quarter ended September 30, 2003

Form 8-K current report dated August 4, 2003, under Item 5. "Other Matters" the Company issued a news release announcing 2^nd quarter 2003 earnings.

Form 8-K current report dated September 5, 2003, under Item 5. "Other Matters", the Company issued a news release announcing the closing of its PDC 2003-B Drilling Partnership.

Form 8-K current report dated September 30, 2003, under Item 5. "Other Matters", the Company issued a news release announcing reporting that it will post updates on the corporate website regarding a presentation by the President, Steven R. Williams and it will begin reporting the amount of subscription sales from its drilling partnerships on a periodic basis.

Form 8-K current report dated October 6, 2003, under Item 5. "Other Matters", the Company issued a news release announcing the passing of Dale G Rettinger, Executive Vice President and Chief Financial Officer and that Darwin L. Stump, the Company's controller, has been named as acting CFO.

Form 8-K current report dated October 22, 2003, under Item 5. "Other Matters" the Company issued a news release announcing its upcoming third quarter earnings release on November 3^rd and upcoming conference call to discuss earnings on November 4th.

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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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