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 June 30, 2004

[ ] 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 issuer's classes of common stock, as of the latest practicable date: 16,268,294 shares of the Company's Common Stock ($.01 par value) were outstanding as of June 30, 2004.

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 June 30, 2004, the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2004 and 2003, and the related condensed consolidated statements of cash flows for the six-month periods ended June 30, 2004 and 2003. These condensed consolidated financial statements are the responsibility of the Company's management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 the standards of the Public Company Accounting Oversight Board (United States), 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 U. S. generally accepted accounting principles.

KPMG LLP

Pittsburgh, Pennsylvania

July 30, 2004

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

June 30, 2004 and December 31, 2003

(Continued)

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PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets, Continued

June 30, 2004 and December 31, 2003

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 Six Months ended June 30, 2004 and 2003

(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, 2004 and 2003

(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

June 30, 2004

(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

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10. Change in Accounting Principle

11. Acquisition of Oil and Gas Properties

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 June 30, 2004 were $73.9 million compared to $42.2 million for the three months ended June 30, 2003, an increase of approximately $31.7 million or 75.1 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

Drilling revenues for the three months ended June 30, 2004 were $29.5 million compared to $11.9 million for the three months ended June 30, 2003, an increase of approximately $17.6 million or 148 percent. Such increase was due to the increased drilling funds raised through the Company's Public Drilling Programs. The Company started the second quarter of 2004 with advances for future drilling from March 31, 2004 of $21.0 million compared with advances for future drilling of $15.5 million at the beginning of the second quarter of 2003. During the second quarter of 2004 the Company funded a drilling program with subscriptions of $29.0 million compared to an $8.5 million program funded during the second quarter of 2003. Both programs commenced drilling operations shortly after funding. We believe in part that this increase is fueled by the increase in oil and natural gas prices which has improved the performance of our prior programs which in turn has helped to increase our current drilling program sales.

Natural Gas Marketing Activities

Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's gas marketing subsidiary for the three months ended June 30, 2004 were $26.0 million compared to $17.4 million for the three months ended June 30, 2003, an increase of approximately $8.6 million or 49 percent. Such increase was due to higher volumes of natural gas sold and higher average sales prices.

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Oil and Gas Sales

Oil and gas sales from the Company's producing properties for the three months ended June 30, 2004 were $15.9 million compared to $10.9 million for the three months ended June 30, 2003 an increase of $5.0 million or 46 percent. The increase was due to significantly increased volumes sold at higher average sales prices of oil and natural gas. The volume of natural gas sold for the three months ended June 30, 2004 was 2.5 million Mcf at an average sales price of $5.01 per Mcf compared to 2.1 million Mcf at an average sales price of $4.34 per Mcf for the three months ended June 30, 2003. Oil sales were 96,000 barrels at an average sales price of $32.41 per barrel for the three months ended June 30, 2004 compared to 58,000 barrels at an average sales price of $29.52 per barrel for the three months ended June 30, 2003. The increase in natural gas volumes was the result of the Company's increased investment in oil and gas properties, recompletions of existing wells, two fourth quarter 2003 acqui sitions of oil and gas properties in Colorado and Kansas and the investment in oil and gas properties we own in our public drilling program partnerships.

The Company's oil and natural gas production by area of operations along with average sales price is presented below:

Our 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 and oil markets has remained prevalent in the last few years and can have a material impact on our financial results. 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 and 2004, 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 re gion. 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 the startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from 78% to 91% for an average of 86% of the NYMEX price, levels consistent with historical price relationships before the local demand/pipeline capacity problem. The Company has commodity price hedging contracts for oil and natural gas production from July 2004 through October 2005 to protect against possible sh ort-term price weaknesses.

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Oil and Gas Hedging Activities

Because of uncertainty surrounding natural gas prices we have used various hedging instruments to manage some of the impact of fluctuations in prices. Through October of 2005 we have in place a series of floors and ceilings and hedges on part of our natural gas and oil 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 June 30, 2004 the Company averaged natural gas volumes sold of 849,000 Mcf per month and oil sales of 32,000 barrels per month. The current positions in effect on the Company's share of production are shown in the following table.

Well Operations, Pipeline and Other Income

Well operations and pipeline income for the three months ended June 30, 2004 was $1.9 million compared to $1.8 million for the three months ended June 30, 2003, an increase of approximately $100,000 or 5.6 percent. Such increase was due to an increase in the number of wells and pipeline systems operated by the Company for our drilling program partnerships as well as third parties. Other income for the three months ended June 30, 2004 was $687,000 compared to $285,000 for the three months ended June 30, 2003.

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Costs and Expenses

Costs and expenses for the three months ended June 30, 2004 were $60.5 million compared to $35.3 million for the three months ended June 30, 2003, an increase of approximately $25.2 million or 71.4 percent. Such increase was primarily the result of increased cost of oil and gas well drilling operations, cost of gas marketing activities, oil and gas production costs and depreciation, depletion and amortization.

Oil and Gas Well Drilling Operations Costs

Oil and gas well drilling operations costs for the three months ended June 30, 2004 were $25.0 million compared to $10.1 million for the three months ended June 30, 2003, an increase of approximately $14.9 million or 148 percent. Such increase was due to the higher levels of drilling activity from our Public Drilling Programs referred to above.

Cost of Gas Marketing Activities

The costs of gas marketing activities for the three months ended June 30, 2004 were $25.6 million compared to $17.1 million for the three months ended June 30, 2003, an increase of $8.5 million or 49.7 percent. The increase was due to higher volumes of natural gas purchased for resale, along with higher average purchase prices. Income before income taxes for the Company's natural gas marketing subsidiary improved from $125,000 for the three months ended June 30, 2003 to $360,000 for the three months ended June 30, 2004. 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

Oil and gas production costs from the Company's producing properties for the three months ended June 30, 2004 were $4.0 million compared to $3.5 million for the three months ended June 30, 2003, an increase of approximately $500,000 or 14.3 percent. Such increase was due to the increased production costs on the increased volumes of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. Lifting cost per Mcfe increased from $0.98 per Mcfe during the three months ended June 30, 2003 to $1.02 per Mcfe during the three months ended June 30, 2004, primarily as a result of production taxes on higher average prices of gas and oil sold.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2004 were $900,000 compared to $1.2 million for the three months ended June 30, 2003, a decrease of approximately $300,000 or 25%. Such decrease was due to the change of and restructuring of executives' compensation offset in part by increased administrative activity associated with an expanding Company.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization costs for the three months ended June 30, 2004 increased to $4.7 million from approximately $3.1 million for the three months ended June 30, 2003, an increase of approximately $1.6 million or 51.6 percent. Such increase was due to the significantly increased production and investment in oil and gas properties by the Company.

Interest Expense

Interest costs for the three months ended June 30, 2004 and 2003 remained relatively constant at approximately $250,000 in both periods. The Company utilizes its daily cash balances to reduce its line of credit to lower its costs of interest.

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Provision for Income Taxes

The effective income tax rate for the Company's provision for income taxes increased from approximately 33 percent to 36 percent primarily as a result of the application of higher tax rates due to significantly increased earnings of the Company during 2004 and other miscellaneous permanent differences which are not expected in 2004.

Net income and Earnings Per Share

Net income for the three months ended June 30, 2004 was $8.6 million compared to a net income of $4.6 million for the three months ended June 30, 2003, an increase of approximately $4.0 million or 87 percent.

Diluted earnings per share for the three months ended June 30, 2004 was $0.52 per share compared to $0.29 per share for the three months ended June 30, 2003, an increase of $0.23 per share or 79.3 percent.

Revenues

Total revenues for the six months ended June 30, 2004 were $145.0 million compared to $96.2 million for the six months ended June 30, 2003, an increase of approximately $48.8 million or 50.7 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

Drilling revenues for the six months ended June 30, 2004 were $59.0 million compared to $33.4 million for the six months ended June 30, 2003, an increase of approximately $25.6 million or 76.6 percent. Such increase was due to the increased drilling funds raised through the Company's Public Drilling Programs. The Company started the second quarter of 2004 with advances for future drilling from March 31, 2004 of $21.0 million compared with advances for future drilling of $15.5 million at the beginning of the second quarter of 2003. During the second quarter of 2004 the Company funded its first drilling program of the year with subscriptions of $29.0 million compared to an $8.4 million program funded during the second quarter of 2003. Both programs commenced drilling operations shortly after funding. We believe in part that this increase results from higher oil and natural gas prices which have improved the performance of our prior programs helping to increase our current drilling program sales.

Natural Gas Marketing Activities

Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary, for the six months ended June 30, 2004 were $49.5 million compared to $39.0 million for the six months ended June 30, 2003, an increase of approximately $10.5 million or 26.9 percent. Such increase was due to higher volumes of natural gas sold, along with higher average sales prices.

Oil and Gas Sales

Oil and gas sales from the Company's producing properties for the six months ended June 30, 2004 were $32.1 million compared to $19.8 million for the six months ended June 30, 2003 an increase of $12.3 million or 62.1 percent. The increase was due to significantly increased volumes sold at higher average sales prices of oil and natural gas. The volume of natural gas sold for the six months ended June 30, 2004 was 5.2 million Mcf at an average sales price of $4.96 per Mcf compared to 3.8 million Mcf at an average sales price of $4.41 per Mcf for the six months ended June 30, 2003. Oil sales were 200,200 barrels at an average sales price of $32.11 per barrel for the six months ended June 30, 2004 compared to 115,000 barrels at an average sales price of $27.80 per barrel for the six months ended June 30, 2003. 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 in the second quarter of 2003, recompletions of existing wells, two fourth quarter 2003 acquisitions of oil and gas properties in Colorado and Kansas and the investment in oil and gas properties we own in our public drilling program partnerships.

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The Company's oil and natural gas production by area of operations along with average sales price is presented below:

Our 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 and oil markets has remained prevalent in the last few years and can have a material impact on our financial results. 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 and 2004, 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 re gion. 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 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 local demand/pipeline capacity problem. The Company has commodity price hedging contracts for oil and natural gas production from July 2004 through October 2005 to protect against possible short-term price wea knesses. See Management's Discussion and Analysis for the three months ended June 30, 2004 compared with June 30, 2003 for a complete schedule of current hedging positions.

Well Operations, Pipeline and Other Income

Well operations and pipeline income for the six months ended June 30, 2004 was $3.7 million compared to $3.4 million for the six months ended June 30, 2003, an increase of approximately $300,000 or 8.8 percent. Such increase was due to an increase in the number of wells and pipeline systems operated by the Company for our drilling program partnerships as well as third parties. Other income for the six months ended June 30, 2004 was $745,000 compared to $670,000 for the six months ended June 30, 2003.

Costs and Expenses

Costs and expenses for the six months ended June 30, 2004 were $118.3 million compared to $81.8 million for the six months ended June 30, 2003, an increase of approximately $36.5 million or 44.6 percent. Such increase was primarily the result of increased cost of oil and gas well drilling operations, cost of gas marketing activities, oil and gas production costs and depreciation, depletion and amortization.

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Oil and Gas Well Drilling Operations Costs

Oil and gas well drilling operations costs for the six months ended June 30, 2004 were $50.3 million compared to $27.8 million for the six months ended June 30, 2003, an increase of approximately $22.5 million or 80.9 percent. Such increase was due to the higher levels of drilling activity from our Public Drilling Programs referred to above. In addition, the gross margin on the drilling activities for the six months ended June 30, 2004 was 14.6% compared with 16.7% for the six months ended June 30, 2003, a decrease in gross margin of 2.1%. Such decrease was due to increasing well drilling costs particularly the cost of well fracturing and rising steel costs for casing and other well equipment. For competitive reasons the company currently does not plan to increase charges to its investor partners at this time and as a result anticipates a continuation of lower margins in 2004 compared to the prior year.

Cost of Gas Marketing Activities

The cost of gas marketing activities for the six months ended June 30, 2004 were $48.5 million compared to $38.5 million for the six months ended June 30, 2003, an increase of $10 million or 26 percent. The increase was due to higher volumes of natural gas purchased for resale, along with higher average purchase prices. Income before income taxes for the Company's natural gas marketing subsidiary improved from $245,000 for the six months ended June 30, 2003 to $961,000 for the six months ended June 30, 2004. 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

Oil and gas production costs from the Company's producing properties for the six months ended June 30, 2004 were $7.9 million compared to $6.3 million for the six months ended June 30, 2003, an increase of approximately $1.6 million or 25.4 percent. Such increase was due to the increased production costs on the increased volumes of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. Lifting cost per Mcfe increased from $0.99 per Mcfe during the six months ended June 30, 2003 to $1.00 per Mcfe during the six months ended June 30, 2004.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2004 were $1.9 compared to $2.4 million for the six months ended June 30, 2003, a decrease of approximately $500,000 or 20.8 percent. Such decrease was due to the change of and restructuring of executives' compensation offset in part by increased administrative activity associated with an expanding Company.

Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization costs for the six months ended June 30, 2004 increased to $9.2 million from approximately $6.4 million for the six months ended June 30, 2003, an increase of approximately $2.8 million or 43.8 percent. Such increase was due to the significantly increased production and investment in oil and gas properties by the Company.

Interest Expense

Interest costs for the six months ended June 30, 2004 and 2003 remained relatively constant at approximately $500,000 in both periods. The Company utilizes its daily cash balances to reduce its line of credit to lower its costs of interest.

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Provision for Income Taxes

The effective income tax rate for the Company's provision for income taxes increased from approximately 33 percent to 36 percent primarily as a result of the application of higher tax rates due to significantly increased earnings of the Company during 2004 and other miscellaneous permanent differences which are not expected in 2004.

Net income and Earnings Per Share

Net income for the six months ended June 30, 2004 was $17.1 million compared to a net income of $9.4 million for the six months ended June 30, 2003, an increase of approximately $7.7 million or 81.9 percent.

Diluted earnings per share for the six months ended June 30, 2004 was $1.04 per share compared to $0.59 per share for the six months ended June 30, 2003, an increase of $0.45 per share or 76.3 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 and oil from the Company's well interests, natural gas marketing, well drilling and operating activities from the Company's public drilling programs, and natural gas gathering and transportation. 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 Pricing and Pipeline Capacity

Natural gas and oil prices have been volatile in the past, and the Company anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of continuing strong natural gas prices at Henry Hub. Although prices look strong for the remainder of 2004, natural gas storage levels are above normal levels following a period when storage levels had been at five-year lows. The Company believes this situation creates the possibility of periods of both low prices and continued high prices.

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 and 2004, 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 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.

Oil and Gas Hedging Activities

Because of the uncertainty surrounding natural gas and oil prices we have used various hedging instruments to manage some of the impact of fluctuations in gas prices. Through October 2005 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. See previous pages in this Management's Discussion and Analysis for the schedule of hedging positions.

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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 Pricing

Oil prices have strengthened since the middle of 2003. 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 approximately 20% during the six months of 2004, variations in oil prices will have a greater impact on the Company than in the past. The Company also has in place hedges on 10,000 barrels a month for its Wattenberg Field oil production for the period from July 2004 through December 2004 at a price of $31.63 per barrel.

Public Drilling Programs

The Company closed its first partnership (PDC 2004-A) in its PDC 2004-2006 Drilling Program of 2004 in the second quarter and is drilling the wells in the second and third quarters of 2004. This first partnership of 2004 closed with record investor subscriptions of $29.0 million compared to $8.5 million for the first program of 2003.

The Company also closed its second Partnership (PDC 2004-B) of 2004 on July 2, 2004 at a record for a second program at its maximum allowable of $18 million in investor subscriptions nearly two months before its scheduled close. Additional partnerships are scheduled to close in October and December of 2004, with maximum subscriptions of $18 million and $35 million, respectively. Both programs are likely to close early at their maximum allowable subscriptions.

The Company posts daily the current amount of subscriptions in the current partnership at its website, www.petd.com, under the heading of "Drilling Program".

The Company invests, as its equity contribution to each drilling partnership, an additional sum of 22% of the aggregate investor 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. No assurance can be made that the Company will continue to receive this level of funding from the current program 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 $5.6 million. The Company has adequate liquidity to meet this obligation. During the first six months of 2004 the Company has spent $246,800 under this provision.

Common Stock Repurchase

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 June 30, 2004, the Company has repurchased 109,200 shares at an average price of $6.86 per share. The Company intends to fund this repurchase of common stock through internally generated cash flow.

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Long-Term Debt

The Company has a credit facility with J. P. Morgan (formerly Bank One, NA) and BNP Paribas of $100 million subject to adequate oil and natural gas reserves. Currently the borrowing base is set at $80 million while the Company's total oil and gas reserves calculated under this method is in excess of $100 million. As of June 30, 2004 the Company had activated $60 million of this facility. As of June 30, 2004, the outstanding balance on the line of credit was $30.0 million of which $10.0 million was subject to an interest rate swap at a rate of 8.39% and $20.0 million was subject to a prime rate of 4.25%. The above interest rate swap expires on October 12, 2004 at which time the Company will benefit from lower effective interest rate on $10 million of its outstanding credit balance. 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. In the second quarter of 2004, the ban ks and the Company extended the expiration date of the credit agreement until July 3, 2008.

Contractual Obligations

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 cost efficiencies. Management believes that the Company has adequate capital to meet its operating requirements.

Commitments and Contingencies

As Managing General Partner of 10 private partnerships and 60 public partnerships, the Company has liability for any potential casualty losses in excess of the partnership assets and insurance. The Company believes its casualty insurance coverage is adequate to meet this potential liability.

Critical Accounting Policies and Estimates

We have identified the following policies as critical to our business operations and the understanding of our results of operations. This listing is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and may require the application of significant judgment by our management; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain e stimates. Those estimates are based on our historical experience, our observance of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see "Note 1 - Summary of significant accounting policies" in our annual financial statements and related notes. Our critical accounting policies and estimates 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.

Accounting for Derivatives Contracts at Fair Value

The Company uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing.

Derivatives are reported on the Condensed Consolidated Balance Sheets at fair value. Changes in fair value of derivatives that are not designated as accounting hedges are recorded in earnings.

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Company's management.

For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value. In addition, for hedges of forecasted transactions, the Company must estimate the expected future cash flows of the forecasted transactions, as well as evaluate the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition in earnings for changes in fair value of certain hedging derivatives.

Use of Estimates in Long-Lived Asset Impairment Testing

Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Company estimates the future cash flows associated with individual assets or groups of assets. Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset's carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Company are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

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Unproved properties or leases are written-off to expense when it is determined that they will expire or be abandoned.

Depreciation, Depletion and Amortization

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

Costs of proved properties including leasehold acquisition, exploration an development costs and equipment are depreciated or depleted by the unit-of-production method based on estimated proved developed oil and gas reserves.

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 is not expected to be realized, 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 June 2001, the Financial Accounting Standard Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations" that required entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement was effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $271,800 and a related liability of $592,100 (using a 6% discount rate) and a cumulative effect of change in accounting principle on prior years of $198,600 (net of taxes of $121,700).

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 amended 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 amended the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements. Disclosures required by this standard are included in the notes to these financial statements.

The FASB issued FIN 46, "Consolidation of Variable Interest Entities", in January 2003 and amended the interpretation in December 2003. A variable interest entity (VIE) is an entity in which its voting equity investors lack the characteristics of having a controlling financial interest or where the existing capital at risk is insufficient to permit the entity to finance its activities without receiving additional financial support from other parties. FIN 46 requires the consolidation of entities which are determined to be VIEs when the reporting company determines itself to be the primary beneficiary (the entity that will absorb a majority of the VIE's expected losses, receive a majority of the VIE's residual returns, or both). The amended interpretation was effective for the first interim or annual reporting period ending after March 15, 2004, with the exception of special purpose entities for which the statement was effective for periods ending after December 15, 2003. We h ave completed a review of our partnership investments and have determined that those entities do not qualify as VIEs.

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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 of mineral rights (leases) 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 $7,226,600 and $7,576,900 of mineral rights associated with undeveloped oil and gas pr operties as of June 30, 2004 and December 31, 2003, respectively, and $16,929,100 and $15,485,500 of mineral rights associated with developed oil and gas properties as of June 30, 2004 and December 31, 2003, 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. There is a proposed FASB staff position issued that clarifies that reclassification will not be necessary under the exception to SFAS No. 142 but the comment period is still open. Final resolution is expected by the end of the Company's third quarter.

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, 2003.

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 for Appalachian and Michigan production and CIG-based contracts traded by JP Morgan for Colorado production. 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 and, in the case of RNG, the cost of gas supplies purchased for marketing activities. As a result, while these hedging arrangements are structured to reduce the Company's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Company might otherwise have received from price changes associated with the hedged commodity. The Company's policy prohibits the use of natural gas future and option contracts for speculative purposes.

The following tables summarize the open futures and options contracts for Riley Natural Gas and PDC as of June 30, 2004 and June 30, 2003.

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The maximum term over which RNG is hedging exposure to the variability of cash flows for commodity price risk is 36 months.

The average NYMEX closing price for natural gas for the years 2003 and 2002 was $5.39 Mmbtu and $3.22 Mmbtu. The average NYMEX closing price for oil for the years 2003 and 2002 was $30.98 bbl and $26.98 bbl. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulation and new drilling activities within the industry.

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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 chang es 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 and 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 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

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Item 4. Submission of Matters to a Vote of Security Holders

The Company held its annual meeting of shareholders on June 11, 2004. For the results of the meeting, see the Company's Form 8-K dated June 11, 2004.

Item 6. Exhibits and Reports on Form 8-K

1. Exhibits

(b) Reports on Form 8-K during the quarter ended June 30, 2004.

Form 8-K current report dated May 5, 2004, under Item 5, "Other Matters", the Company issued a news release announcing financial and operating results for the first quarter 2004.

Form 8-K current report dated May 11, 2004, under Item 5, "Other Matters", the Company issued a news release announcing that is has closed its first 2004 Partnership with record $29 Million in subscriptions.

Form 8-K current report dated May 12, 2004, under Item 5, "Other Matters", the Company issued a news release announcing that is has added to previously announced natural gas and oil commodities options positions.

Form 8-K current report dated June 11, 2004, under Item 5, "Other Matters", the Company issued a news release announcing that shareholders of the company re-elected Vincent F. D'Annunzio and Thomas E. Riley to the Board of Directors of the company for a three-year term and David C. Parke to the Board of Directors of the company for a one year term. Each of the directors received 99 percent of the votes cast in favor of their re-election. The shareholders ratified the selection of KPMG LLP as independent auditors for the fiscal year ending December 31, 2004. The shareholders also approved the 2004 Long-Term Equity Compensation Plan and the Non-Employee Director Deferred Compensation 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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