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10-K 1 pdc10k98d03.htm CONFORMED COPY

CONFORMED COPY

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

[X]ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

Commission File Number 333-41977-04

[] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction

period from to

PDC 1998-D LIMITED PARTNERSHIP

(Exact name of registrant as specified in its charter)

West Virginia

(State or other jurisdiction of

incorporation or organization)

55-0757539
(I.R.S. Employer
Identification No.)

103 East Main Street, Bridgeport, West Virginia 26330

(Address of principal executive offices) (zip code)

Registrant's telephone number, including area code (304) 842-3597

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

General and Limited Partnership Interests

(Title of class)

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 and (2) has been subject to such filing requirements for the past 90 days. Yes X No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

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

There is no trading market for the registrant's securities.

PART I

ITEM 1. BUSINESS.

General

PDC 1998-D Limited Partnership ("the Partnership") is a limited partnership formed on December 31, 1998 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing General Partner of the Partnership.

Since the commencement of operations on December 31, 1998, the Partnership has been engaged in onshore, domestic gas exploration exclusively in the northern Appalachian and Michigan Basins. A total of 11 limited partners contributed initial capital of $330,000; a total of 1,045 additional general partners contributed initial capital of $20,195,261; and PDC (Managing General Partner) contributed $4,464,244 in capital as a participant in accordance with contribution provisions of the Limited Partnership Agreement (the Agreement). During 1999 in accordance with the Partnership Agreement, all Additional General Partners were converted to Limited Partners.

Under the terms of the Agreement, the allocation of revenues is as follows:

	Allocation of Revenues
Additional General and Limited Partners	80%
Managing General Partner	20%

Operating and direct costs are allocated and charged to the additional general and limited partners and the Managing General Partner in the same percentages as revenues are allocated. Leasehold, drilling and completion costs, and equipment costs are borne 80% by the additional general and limited partners and 20% by the Managing General Partner. See Footnote 4 of financial statements for a complete description of the allocation of Partnership revenue and costs.

Employees

The Partnership has no employees, however, PDC has approximately 110 employees which include a staff of geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership's operations.

Plan of Operations

The Partnership participated in the drilling of 97 gross wells (89 gross productive wells) and will continue to operate and produce its productive wells. The Partnership does not have unexpended initial capital and no additional drilling activity is planned.

See Item 2 herein for information concerning the Partnership's gas wells.

Markets for Oil and Gas

The availability of a market for any oil and gas produced from the operations of the Partnership will depend upon a number of factors beyond the control of the Partnership which cannot be accurately predicted. These factors include the proximity of the Partnership wells to and the capacity of natural gas pipelines, the availability and price of competitive fuels, fluctuations in seasonal supply and demand, and government regulation of supply and demand created by its pricing and allocation restrictions. Oversupplies of gas can be expected to occur from time to time and may result in the Partnership's wells being shut-in or curtailed. Increased imports of oil and natural gas have occurred and are expected to continue. The effects of such imports could adversely impact the market for domestic oil and natural gas. All oil and gas is sold under contracts based on market sensitive indexes that vary from month to month. No fixed price contracts are in place. The Partnership sold oil and natural gas to two customers which accounted for 98.86% and 1.14% of the Partnership's total oil and natural gas sales for the year ended December 31, 2003 and 98.07 % and 1.93% for 2002, respectively.

Hedging Activities

The Managing General Partner, through its subsidiary Riley Natural Gas (RNG), utilizes commodity-based derivative instruments as hedges to manage a portion of the Partnership's exposure to price volatility stemming from its natural gas sales and marketing activities. These instruments consist of NYMEX traded natural gas futures and option contracts for Appalachian and Michigan production. The contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within the next twenty-four-month period. The Managing General Partner does not hold natural gas futures or options for speculative purposes and permits utilization of hedges only if there is an underlying physical position.

The Managing General Partner has extensive experience with the use of financial hedges to reduce the risk and impact of natural gas price changes. These hedges are used to "lock in" fixed prices from time to time for the Partnership's share of production, and to establish "floors" and "ceilings" or "collars" on the possible range of the price realized for the sale of natural gas and oil. In order for contracts to serve as effective hedges, there must be sufficient correlation to the underlying hedged transaction. While hedging can help provide price protection if spot prices drop, hedges can also limit upside potential.

For unhedged natural gas sales not subject to fixed price contracts, the Partnership is subject to price fluctuations for natural gas sold in the spot market. The Managing General Partner continues to evaluate the potential for reducing these risks by entering into hedge transactions.

Competition

The Partnership competes in marketing its gas with numerous companies and individuals, many of which have financial resources, staffs and facilities substantially greater than those of the Partnership or Petroleum Development Corporation.

State Regulations

State regulatory authorities have established rules and regulations requiring permits for well operations, reclamation bonds and reports concerning operations. States also have statutes and regulations concerning the spacing of wells, environmental matters and conservation, and have established regulations concerning the unitization and pooling of oil and gas properties and maximum rates of production from oil and gas wells. The Partnership believes it has complied in all material respects with applicable state regulations. The Partnership estimates it has spent approximately $3,300 and $2,100 in 2003 and 2002, respectively to comply with federal and state regulations.

Federal Regulations

Regulation of Liquid Hydrocarbons. Liquid hydrocarbons (including crude oil and natural gas liquids) were subject to federal price and allocation controls until January 1981 when controls were effectively eliminated by executive order of the President. As a result, to the extent the Partnership sells oil produced from its properties, those sales are at unregulated market prices.

Although it appears unlikely under present circumstances that controls will be reimposed upon liquid hydrocarbons, it is possible Congress may enact such legislation at a future date.

Natural Gas Regulation. Sale of natural gas by the Partnership is subject to regulation of production, transportation and pricing by governmental regulatory agencies. Generally, the regulatory agency in the state where a producing well is located regulates production activities and, in addition, the transportation of gas sold intrastate. The Federal Energy Regulatory Commission (FERC) regulates the operation and cost of interstate pipeline operators who transport gas. Currently the price of gas to be sold by the Partnership is not regulated by any state or federal agency.

Proposed Regulation. Numerous proposals concerning energy are being considered by the United States Congress, various state legislatures and regulatory agencies. The possible outcome and effect of these proposals cannot be accurately predicted.

Environmental and Safety Regulation. The Partnership believes that it complies, in all material respects, with all legislation and regulations affecting its operations in the drilling and production of oil and gas wells and the discharge of wastes. To date, compliance with such provisions and regulations has not had a material effect upon the Partnership's expenditures for capital equipment, its operations or its competitive position. The cost of such compliance is not anticipated to be material in the future.

ITEM 2. PROPERTIES.

Drilling Activity

The following table sets forth the results of drilling activity of the Partnership which was conducted in the Continental United States.

Development Wells
Gross Wells			Net Wells
Productive	Dry	Total	Productive	Dry	Total
89	5	94	65.81	4.88	70.69

The Partnership drilled three dry exploratory wells (2.69 net), two in Colorado and one in Michigan. No additional drilling activity is planned.

Production

See "Management's Discussion and Analysis" on page 6 for Partnership production.

Reserves

See "Footnote 7" to the Partnership's financial statements for the Partnership's oil and gas reserves.

Summary of Productive Wells

During 2002 the Partnership transferred five wells in the Paxton Quarry Antrim Unit in Michigan to an unrelated third party. The Partnership received no proceeds or incurred no costs in this transaction. The table below shows the number of the Partnership's gross and net wells by state as of December 31, 2003.

	Natural Gas Wells
Location	Gross	Net
Michigan	32	12.28
Pennsylvania	42	40.83
West Virginia	10	9.96
Total	84	63.07

A "productive well" is a well producing, or capable of producing, oil and gas in commercial quantities. For purposes of the above table, a "gross well" is one in which the Partnership has a working interest and a "net well" is a gross well multiplied by the Partnership's working interest to which it is entitled under its drilling agreement.

Title to Properties

The Partnership's interests in producing acreage are in the form of assigned direct interests in leases. Such properties are subject to customary royalty interests generally contracted for in connection with the acquisition of properties and could be subject to liens incident to operating agreements, liens for current taxes and other burdens. The Partnership believes that none of these burdens materially interfere with the use of such properties in the operation of the Partnership's business.

As is customary in the oil and gas industry, little or no investigation of title is made at the time of acquisition of undeveloped properties (other than a preliminary review of local mineral records). Investigations are generally made, including in most cases receiving a title opinion of legal counsel, before commencement of drilling operations. A thorough examination of title has been made with respect to all of the Partnership's producing properties and the Partnership believes that it has generally satisfactory title to such properties.

ITEM 3. LEGAL PROCEEDINGS.

The Managing General Partner as driller/operator is not party to any legal action that would materially affect the Managing General Partner's or Partnership's operations or financial statements.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Not Applicable.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

At December 31, 2003, PDC 1998-D Limited Partnership had one Managing General Partner, 11 Limited Partners who fully paid for 16.5 units at $20,000 per unit of limited partnership interests and a total of 1,045 Additional General Partners who fully paid for 1,009.76305 units at $20,000 per unit of additional general partnership interests. During 1999 in accordance with the Partnership Agreement, all Additional General Partners were converted to Limited Partners. No established public trading market exists for the interests.

Limited and additional general partnership interests are transferable, however no assignee of an interest in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. There is no established trading market for the securities of the Partnership.

ITEM 6. SELECTED FINANCIAL DATA.

The selected financial data presented below has been derived from audited financial statements of the Partnership appearing elsewhere herein.

	Years Ended December 31,
		2003	2002	2001
Oil and Gas Sales		$2,469,093	1,749,877	2,568,583
Costs and Expenses		1,328,404	1,391,940	1,684,808
Cumulative effect of change in accounting principle		(14,001)	-	-
Net Income (loss)		1,127,699	359,528	891,733
Allocation of Net Income:
Managing General Partner		225,539	71,906	178,347
Limited and Additional General Partners		902,160	287,622	713,386
Per Limited and Additional General Partner Unit		879	280	695
Total Assets		6,380,862	6,876,225	7,489,808
Distributions:
Managing General Partner		165,810	181,197	367,157
Limited and Additional General Partners		1,463,308	808,663	1,468,640

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS.

Liquidity and Capital Resources

The Partnership was funded with initial Limited and Additional General Partner contributions of $20,525,261 and the Managing General Partner contributed $4,464,244 in accordance with the Agreement. Syndication and management fee costs of $2,668,284 were incurred leaving available cash of $22,321,221 for Partnership activities.

The Partnership began exploration and development activities subsequent to the funding of the Partnership and completed these activities by December 31, 1999. Ninety-seven wells have been drilled, 89 of which have been completed as producers, currently the Partnership has eighty-four producing wells. No additional wells will be drilled.

The Partnership had working capital at December 31, 2003 of $338,714.

Operations are expected to be conducted with available funds and revenues generated from oil and gas activities. No bank borrowings are anticipated.

Results of Operations

2003 Compared to 2002

Oil and gas sales for the year ended December 31, 2003 were $2,469,093 compared to $1,749,877 for the year ended December 31, 2002. The volume of natural gas sold for the year ended December 31, 2003, was 518,437 Mcf at an average sales price of $4.76 per Mcf compared to 597,799 Mcf at an average sales price of $2.93 per Mcf for the year ended December 31, 2002. Oil sales were 124 barrels at an average price of $26.84 per barrel for the year ended December 31, 2003 compared to 60 barrels at an average price of $14.68 per barrel for the year ended December 31, 2002. The lifting costs for the year ended December 31, 2003 was $1.53 per Mcfe compared to $1.25 per Mcfe for the year ended December 31, 2002. This increase is partially attributed to the increase in severance and property taxes. The fixed costs of operations and well maintenance are allocated to lower production volumes, therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization decreased from $623,393 for the year ended December 31, 2002 to $515,111 for the year ended December 31, 2003 as a result of lower volumes of natural gas sold. Cash distributions to the partners amounted to $1,629,118 in 2003.

2002 Results Compared to 2001

Oil and gas sales for the year ended December 31, 2002 were $1,749,877 compared to $2,568,583 for the year ended December 31, 2001. The volume of natural gas sold for the year ended December 31, 2002, was 597,799 Mcf at an average sales price of $2.93 per Mcf compared to 696,981 Mcf at an average sales price of $3.68 per Mcf for the year ended December 31, 2001. Oil sales were 60 barrels at an average price of $14.68 per barrel for the year ended December 31, 2002 compared to 58 barrels at an average price of $18.77 per barrel for the year ended December 31, 2001. The lifting costs for the year ended December 31, 2002 was $1.25 per Mcfe compared to $1.14 per Mcfe for the year ended December 31, 2001. This increase is partially attributed to the increase in severance and property taxes. The fixed costs of operations and well maintenance are allocated to lower production volumes, therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization decreased from $865,169 for the year ended December 31, 2001 to $623,393 for the year ended December 31, 2002 as a result of lower volumes of natural gas sold. Cash distributions to the partner's amounted to $989,860 in 2002.

Critical Accounting Policies and Estimates

Certain accounting policies are very important to the portrayal of the Partnership's financial condition and results of operations and require management's most subjective or complex judgments. In applying those policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. 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 account policies" in our financial statements and related notes. The Partnership's critical accounting policies and estimates are as follows:

Revenue Recognition

Sales of oil and natural gas are recognized when the right and responsibilities of ownership passes to the purchasers and are net of royalties.

Accounting for Derivatives Contracts at Fair Value

The Partnership 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 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 Partnership 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 Partnership'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 Partnership 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.

Oil and Gas Properties

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

The Partnership 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.

New Accounting Standards

In June 2001, the Financial Accounting Standard Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations" that requires 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 is effective for fiscal years beginning after June 15, 2002. The Partnership adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $14,491 and a related liability of $28,491 (using a 6% discount rate) and a cumulative effect of change in accounting principle on prior years of $14,001.

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 Partnership 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 Partnership would be required to reclassify the historical cost of approximately $460,141 of mineral rights associated with developed oil and gas properties as of December 31, 2003 and 2002 out of oil and gas properties and into a separate intangible mineral rights assets line item. The Partnership's total balance sheet, cash flows and results of operations would not be affected since such intangible assets would continue to be amortized and assessed for impairment.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk.

Market-Sensitive Instruments and Risk Management

The Partnership's primary market risk exposure is commodity price risk. This exposure is discussed in detail below:

Commodity Price Risk

Natural gas and oil prices have been unusually volatile for the past few years, and the Partnership 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 2004 although natural gas storage levels are near normal levels following a period where storage had been at a five year low. The Partnership believes this situation creates the possibly of both periods of low prices and continued high prices.

Because of the uncertainty surrounding gas prices the Managing General Partner used hedging agreements to manage some of the impact of fluctuations in prices for the Managing General Partner and its various limited partnership's share of the production. Through October of 2004 the Partnership has in place a series of costless collars and option contracts. Under the collar arrangements, if the applicable index rises above the ceiling price, the Partnership pays the counterparty, however if the index drops below the floor the counterparty pays the Partnership. These floor and ceiling prices were set at levels which allowed the Partnership to set floors on two units of production for each unit of production with a ceiling. For the period from January 2004 through March 2004, the Partnership has floors in place in a range from $4.20 to $4.45 on 16,420 Mmbtu of monthly production and ceilings in place in a range from $5.00 to $5.40 on 8,210 Mmbtu of monthly production. For the period April 2004 through October 2004, the Partnership has floors in place at $4.00 on 11,729 Mmbtu of monthly production and ceilings in place at $5.65 on 11,729 Mmbtu of monthly production. As of December 31, 2003 the Partnership had option contracts for the sale of 106,730 Mmbtu of natural gas with an average ceiling price of $5.55 and for the sale of 131,360 Mmbtu of natural gas with an average floor price of $4.12. The fair value of open contracts as of December 31, 2003 is ($19,047).

The average NYMEX closing price for natural gas for the years 2003, 2002 and 2001 was $5.39 per Mmbtu, $3.22 per Mmbtu, and $4.27 per Mmbtu with a range from $1.83 per Mmbtu to $9.98 per Mmbtu. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulations and new drilling activities within the industry.

Disclosure of Limitations

As the information above incorporates only those exposures that exist at December 31, 2003, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.

Part III

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA:

The response to this Item is set forth herein in a separate section of this Report, beginning on Page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE.

NONE.

ITEM 9A. CONTROLS AND PROCEDURES

Under the supervision and with the participation of the Managing General Partner's management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, the Managing General Partner 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 the period covered by this annual report on Form 10-K, 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 Managing General Partner'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 in the fourth quarter and subsequent to the date of their evaluation.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY.

The Partnership has no directors or executive officers. The Partnership is managed by Petroleum Development Corporation (the Managing General Partner). Petroleum Development Corporation's common stock is traded in the NASDAQ National Market and Form 10-K for 2003 has been filed with the Securities and Exchange Commission.

ITEM 11. EXECUTIVE COMPENSATION.

NON-APPLICABLE.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

NON-APPLICABLE.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Pursuant to the authorization contained in the Limited Partnership Agreement, PDC receives fees for services rendered and reimbursement of certain expenses from the Partnership. See respective drilling prospectus for further information regarding the Limited Partnership Agreement. The following table presents compensation or reimbursements by the Partnership to PDC or other related parties for the years listed below:

	Years Ended December 31,
	2003	2002	2001
Lifting costs	$794,988	745,099	793,214
Tax return preparation	8,886	8,847	8,805
Direct administrative cost	642	5,848	2,239

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2003, 2002 and 2001, KPMG LLP provided auditing services in the amount of $5,997, $5,822 and $5,599, respectively.

Pre-Approval Policies and Procedures

The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent accountants be subject to pre-approval by the Audit Committee or authorized members of the Committee. Since the Partnership does not have an Audit Committee, the Managing General Partner's Audit Committee also serves for the Partnership. The Audit Committee has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent accountants. Services necessary to conduct the annual audit must be pre-approved by the Audit Committee or by the authorized Audit Committee member. Actual fees incurred for all services performed by the independent accountant will be reported to the Audit Committee after the services are fully performed.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(a) (1) Financial Statements

See Index to Financial Statements on F-2

(2) Financial Statement Schedules

See Index to Financial Statements on page F-2. All financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto.

(b) Reports on Form 8-K during the fourth quarter.

None.

4.1

Form of Limited Partnership Agreement (incorporated by reference to Appendix A to Form S-1, SEC File No. 333-41977, and Rule 424 final prospectus, dated June 19 1998, of PDC 2000 Drilling Program, filed with the SEC on June 30, 1998).

14

Code of Ethics of Petroleum Development Corporation (incorporated by reference to the posted code on the web site of Petroleum Development Corporation at www.petd.com).

31.1

Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership.

31.2

Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership.

32.1

Certification of Chief Executive Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership under Title 18 United States Code section 1350.

32.2

Certification of Chief Financial Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership under Title 18 United States Code section 1350.

CONFORMED COPY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

	PDC 1998-D Limited Partnership By its Managing General Partner Petroleum Development Corporation
	By /s/ Steven R. Williams Steven R. Williams, Chairman
	March 25, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	Date



/s/ Steven R. Williams Steven R. Williams	Chairman, Chief Executive Officer, President and Director	March 25, 2004

/s/ Darwin L. Stump Darwin L. Stump	Chief Financial Officer and Treasurer (principal financial and accounting officer)	March 25, 2004

/s/ Thomas E. Riley Thomas E. Riley	Executive Vice President of Production , Natural Gas Marketing and Business Development and Director	March 25, 2004

/s/ Donald B. Nestor Donald B. Nestor	Director	March 25, 2004

/s/ Vincent F. D'Annunzio Vincent F. D'Annunzio	Director	March 25, 2004

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Statements for Annual Report

on Form 10-K to Securities and Exchange

Commission

Years Ended December 31, 2003, 2002 and 2001

(With Independent Auditors' Report Thereon)

F-1

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Index to Financial Statements


Independent Auditors' Report	F-3
Balance Sheets - December 31, 2003 and 2002	F-4
Statements of Operations - Years Ended December 31, 2003, 2002 and 2001	F-5
Statements of Partners' Equity and Comprehensive Income- Years Ended December 31, 2003, 2002 and 2001	F-6
Statements of Cash Flows - Years Ended December 31, 2003, 2002 and 2001	F-7
Notes to Financial Statements	F-8

All financial statement schedules have been omitted because they are not applicable or not required or the required information is shown in the financial statements or notes thereto.

F-2

Independent Auditors' Report

To the Partners

PDC 1998-D Limited Partnership:

We have audited the financial statements of PDC 1998-D Limited Partnership (a West Virginia limited partnership) as listed in the accompanying index. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PDC 1998-D Limited Partnership as of December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003, in conformity with with accounting principles generally accepted in the United States of America

As discussed in note 1 to the financial statements, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations", in 2003. Also, as discussed in note 1 to the financial statements, the Partnership changed its method of accounting for derivative instruments and hedging activities in 2001.

KPMG LLP

Pittsburgh, Pennsylvania

March 15, 2004

F-3

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Balance Sheets

December 31, 2003 and 2002

Assets	2003	2002


Cash	$ 2,664	1,816
Accounts receivable - oil and gas revenues	378,092	373,683
Total current assets	380,756	375,499

Oil and gas properties, successful efforts method (notes 3 and 5):	10,146,279	10,123,711
Less accumulated depreciation, depletion, and amortization	4,146,173	3,622,985
	6,000,106	6,500,726

	$6,380,862	6,876,225

Liabilities and Partners' Equity

Current liabilities:
Accrued expenses	$ 42,042	111,913
Total current liabilities	42,042	111,913

Asset retirement obligation	30,201	-

Partners' equity	6,308,619	6,764,312

	$6,380,862	6,876,225

See accompanying notes to financial statements.

F-4

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Operations

Years Ended December 31, 2003, 2002 and 2001

	2003	2002	2001
Revenues:
Sales of oil and gas	$2,469,093	1,749,877	2,568,583
Interest income	1,011	1,591	7,958
	2,470,104	1,751,468	2,576,541

Expenses (note 3):
Lifting cost	794,988	745,099	793,214
Independent audit fee	5,997	5,822	5,599
Franchise taxes	2,780	2,931	3,433
Tax return preparation	8,886	8,847	8,805
Direct administrative cost	642	5,848	2,239
Independent engineering cost	-	-	6,349
Depreciation, depletion and amortization	515,111	623,393	865,169
	1,328,404	1,391,940	1,684,808

Income before cumulative effect of change in accounting principle	1,141,700	359,528	891,733

Cumulative effect of change in accounting principle	(14,001)	-	-

Net income	$ 1,127,699	359,528	891,733

Net income per limited and additional general partner unit before cumulative effect of change in accounting principle	$ 890	280	695

Cumulative effect of change in accounting principle	(11)	-	-

Net income per limited and additional general partner unit	$ 879	280	695

See accompanying notes to financial statements.

F-5

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Partners' Equity and Comprehensive Income

Years Ended December 31, 2003, 2002 and 2001

	Limited and Additional General Partners	Managing General Partner	Accumulated Other Comprehensive Income (Loss)	Total
Balance December 31, 2000	$ 6,722,784	1,680,697		8,403,481

Distributions to partners	(1,468,640)	(367,157)		(1,835,797)

Comprehensive income:
Net income (loss)	713,386	178,347		891,733
Cumulative effect of change in accounting principle - January 1, 2001			(1,618,538)
Changes in fair value of outstanding hedging positions			821,042
Reclassification adjustment for settled contracts included in net income (loss)			797,496
Other comprehensive income			-	-
Comprehensive income				891,733

Balance December 31, 2001	5,967,530	1,491,887	-	7,459,417

Distributions to partners	(808,663)	(181,197)		(989,860)

Comprehensive income:
Net income (loss)	287,622	71,906		359,528
Change in fair value of outstanding hedging positions			(64,773)
Reclassification adjustment for settled contracts included in net income (loss)			-
Other comprehensive loss			(64,773)	(64,773)
Comprehensive income				294,755

Balance December 31, 2002	5,446,489	1,382,596	(64,773)	6,764,312

Distributions to partners	(1,463,308)	(165,810)		(1,629,118)

Comprehensive income:
Net income (loss)	902,160	225,539		1,127,699
Change in fair value of outstanding hedging positions			36,952
Reclassification adjustment for settled contracts included in net income (loss)			8,774
Other comprehensive income			45,726	45,726
Comprehensive income				1,173,425

Balance December 31, 2003	$4,885,341	1,442,325	(19,047)	6,308,619

See accompanying notes to financial statements.

F-6

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Cash Flows

Years Ended December 31, 2003, 2002 and 2001

	2003	2002	2001
Cash flows from operating activities:
Net income	$1,127,699	359,528	891,733
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation, depletion and amortization	515,111	623,393	865,169
Cumulative effect of change in accounting principle	14,001	-	-
Accretion of asset retirement obligation	1,709	-	-
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable - oil and gas revenues	(14,971)	(2,120)	76,770
(Decrease) increase in accrued expenses	(13,583)	4,774	(1,580)
Net cash provided from operating activities	1,629,966	985,575	1,832,092

Cash flows from financing activities:
Distributions to partners	(1,629,118)	(989,860)	(1,835,797)

Net cash used by financing activities	(1,629,118)	(989,860)	(1,835,797)

Net increase (decrease) in cash	848	(4,285)	(3,705)
Cash at beginning of year	1,816	6,101	9,806
Cash at end of year	$ 2,664	1,816	6,101

See accompanying notes to financial statements.

F-7

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

Years Ended December 31, 2003, 2002 and 2001

(1) Summary of Significant Accounting Policies

Partnership Financial Statement Presentation Basis

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of PDC 1998-D Limited Partnership (the Partnership). The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities.

Oil and Gas Properties

The Partnership follows the successful efforts method of accounting for the cost of exploring for and developing oil and gas reserves. Under this method, costs of development wells, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, and successful exploratory wells are capitalized and amortized on an annual basis to operations by the units-of-production method using estimated proved developed reserves determined at year end by the Managing General Partner's petroleum engineers. If a determination is made that an exploratory well has not discovered economically producible reserves, then its costs are expensed as dry hole costs.

Revenue Recognition

Sales of oil and natural gas are recognized when the right and responsibilities of ownership passes to the purchaser and are net of royalties. The Partnership sold oil and natural gas to two customers which accounted for 98.86% and 1.14% of the Partnership's total oil and natural gas sales for the year ended December 31, 2003 and 98.07 % and 1.93% for 2002, respectively.

Income Taxes

Since the taxable income or loss of the Partnership is reported in the separate tax returns of the partners, no provision has been made for income taxes on the Partnership's books.

Under federal income tax laws, regulations and administrative rulings, certain types of transactions may be accorded varying interpretations. Accordingly, the Partnership's tax return and, consequently, individual tax returns of the partners may be changed to conform to the tax treatment resulting from a review by the Internal Revenue Service.

(Continued)

F-8

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

Derivative Financial Instruments

The Managing General Partner utilizes commodity based derivative instruments as hedges to manage a portion of the Partnership's exposure to price volatility stemming from natural gas production. These instruments consist of costless collars and option contracts traded on the New York Mercantile Exchange. The costless collars and option contracts hedge committed and anticipated natural gas sales generally forecasted to occur within a 24 month period. The Partnership does not hold or issue derivatives for trading or speculative purposes.

All derivatives are recognized on the Partnership balance sheet at their fair value. On the date the derivative contract is entered into, the Managing General Partner designates the derivative as either a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability ("cash flow" hedge), or a non-hedging derivative. The Managing General Partner formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash-flow hedges to specific firm commitments. The Managing General Partner also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Partnership discontinues hedge accounting prospectively. No hedging activities were discontinued during 2003.

Changes in fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in accumulated other comprehensive income (loss), until earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Partnership discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is dedesignated as a hedging instrument, because it is probable that a forecasted transaction will not occur, or the Partnership determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will discontinue.

The Partnership adopted the provisions of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" (an amendment of FASB Statement No. 133) effective January 1, 2001. The natural gas options are derivatives pursuant to SFAS No. 133/138. The Partnership's derivatives are treated as hedges of committed and/or anticipated transactions. On adoption of this Statement on January 1, 2001, the Partnership recorded a net transition adjustment of ($1,618,538) which was recorded in accumulated other comprehensive income (AOCI). During the year ended December 31, 2001, the Partnership reclassified $797,496, from AOCI into oil and gas sales relating to settled contracts.

By using derivative financial instruments to hedge exposures to changes in commodity prices, the Managing General Partner exposes the Partnership to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnerhip, which creates credit risk. The Managing General Partner minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties.

F-9

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

Use of Estimates

The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and gas reserves and future cash flows from oil and gas properties which are used in assessing impairment of long-lived assets.

New Accounting Standards

(2) Organization

The Partnership was organized as a limited partnership on December 31, 1998 in accordance with the laws of the State of West Virginia for the purpose of engaging in the drilling, completion and operation of oil and gas development and exploratory wells in the Northern Appalachian and Michigan Basins.

Purchasers of partnership units subscribed to and fully paid for 16.5 units of limited partner interests and 1,009.76305 units of additional general partner interests at $20,000 per unit (Investor Partners). Petroleum Development Corporation has been designated the Managing General Partner of the Partnership. Although costs, revenues and cash distributions allocable to the limited and additional general partners are shared pro rata based upon the amount of their subscriptions, including the Managing General Partner to the extent of its capital contributions, there are significant differences in the federal income tax effects and liability associated with these different types of units in the Partnership.

F-10

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

Upon completion of the drilling phase of the Partnership's wells, all additional general partners units are converted into units of limited partner interests and thereafter become limited partners of the Partnership. Limited partners do not have any rights to convert their units into units of additional general partner interests in the Partnership.

In accordance with the terms of the Partnership Agreement (the Agreement), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.

(3) Transactions with Managing General Partner and Affiliates

Years Ended December 31,

  2003

  2002

  2001

Lifting costs

$794,988

745,099

793,214

Tax return preparation

8,886

8,847

8,805

Direct administrative cost

642

5,848

2,239

(4) Allocation

The following table summarizes the participation of the Managing General Partner and the Investor Partners, taking account of the Managing General Partner's capital contribution equal to a minimum of 20% of the initial capital, in the costs and revenues of the Partnership.

	Investor Partners	Managing General Partners
Partnership Costs
Broker-dealer Commissions and Expenses(1)	100%	0%
Management Fee(2)	100%	0%
Undeveloped Lease Costs	0%	100%
Drilling and Completion Costs	80%	20%
Tangible Equipment	0%	100%
Intangible Drilling and Development Costs	100%	0%
Operating Costs(3)	80%	20%
Direct Costs(4)	80%	20%
Administrative Costs	0%	100%

Partnership Revenues

Sale of Oil and Gas Production(5)	80%	20%
Sale of Productive Properties(6)	80%	20%
Sale of Equipment	0%	100%
Sale of Undeveloped Leases	80%	20%
Interest Income	80%	20%

F-11

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(1) Organization and offering costs, net of the dealer manager commissions, discounts, due diligence expenses, and wholesaling fees of the Partnership were paid by the Managing General Partner and not from Partnership funds. In addition, organization and offering costs in excess of 10-1/2% of Subscriptions were paid by the Managing General Partner, without recourse to the Partnership.

(2) Represents a one-time fee paid to the Managing General Partner on the day the Partnership is funded equal to 2-1/2% of total investor subscriptions.

(3) Represents Operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.

(4) The Managing General Partner receives monthly reimbursement from the Partnership for its direct costs incurred by the Managing General Partner on behalf of the Partnership.

To the extent that Investor Partners receive preferred cash distributions, the allocations for Investor Partners will be increased accordingly and the allocation for the Managing General Partner will likewise be decreased.

(6) In the event of the sale or other disposition of a productive well, a lease upon which such well is situated, or any equipment related to any such lease or well, the proceeds from such sale or disposition shall be allocated and credited to the Partners as oil and gas revenues are allocated. The term "proceeds" above does not include revenues from a royalty, overriding royalty, lease interest reserved, or other promotional consideration received by the Partnership in connection with any sale or disposition, which revenues shall be allocated to the Investor Partners and the Managing General Partner in the same percentages that oil and gas revenues are allocated. No such sales have occurred.

(7) In accordance with the repurchase provision of the partnership prospectus, PDC may repurchase units from the investor partners which is entirely voluntary on the part of the partners. During 2003 PDC purchased a total of 1.68 units of partnership interest for a total ownership of 25.42 units as of December 31, 2003 which represents a 2.48% ownership of the original Investor Partners share of limited and additional general partnership units. Therefore, costs and revenues and distributions for these purchased units are allocated to PDC in accordance with the Investor Partners allocation percentages disclosed in this table.

(5) Costs Relating to Oil and Gas Activities

The Partnership is engaged solely in oil and gas activities, all of which are located in the continental United States. Information regarding aggregate capitalized costs and results of operations for these activities is located in the basic financial statements. Costs capitalized for these activities are as follows:

                December 31,

2003

2002

2001

Lease acquisition costs

$ 460,141

460,141

460,141

Intangible development costs

16,510,178

16,510,178

16,510,178

Well equipment

3,917,618

3,917,618

3,917,618

Impairment charge

(10,764,226)

(10,764,226)

(10,764,226)

Capitalized asset retirement cost

     22,568

            -

            -

$ 10,146,279

10,123,711

10,123,711

F-12

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

There were no costs incurred for the Partnership's oil and gas activities for the years ended December 31, 2003, 2002 and 2001.

(6) Income Taxes

As a result of the differences in the treatment of certain items for income tax purposes as opposed to financial reporting purposes, primarily depreciation, depletion and amortization of oil and gas properties and the recognition of intangible drilling costs as an expense or capital item, the income tax basis of oil and gas properties differs from the basis used for financial reporting purposes. At December 31, 2003 and 2002 the income tax basis of the partnership's oil and gas properties was $1,426,382 and $1,798,224, respectively.

(7) Supplemental Reserve Information (Unaudited)

Proved oil and gas reserves of the Partnership have been estimated by the Managing General Partner's petroleum engineer at December 31, 2003, 2002 and 2001. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices. A copy of the reserve report has been made available to all partners. All of the partnership's reserves are proved developed. An analysis of the change in estimated quantities of proved developed oil and gas reserves is shown below:

		Gas (MCF)
		2003	2002	2001
Proved developed reserves:
	Beginning of year	6,248,000	5,746,000	7,304,000
	Revisions of previous estimates	327,000	1,100,000	(862,000)
	Production	(518,000)	(598,000)	(696,000)
	End of year	6,057,000	6,248,000	5,746,000

F-13

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(8) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil

and Gas Reserves (Unaudited)

Summarized in the following table is information for the Partnership with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Partnership proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.

	As of December 31,
	2003	2002	2001
Future estimated revenues	$ 32,492,000	24,688,000	13,219,000
Future estimated production costs	(12,459,000)	(10,263,000)	(6,515,000)
Future estimated development costs	(30,000)	(30,000)	(30,000)
Future net cash flows	20,003,000	14,395,000	6,674,000
10% annual discount for estimated timing of cash flows	(10,194,000)	(7,008,000)	(2,971,000)
Standardized measure of discounted future
estimated net cash flows	$9,809,000	7,387,000	3,703,000

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Years Ended December 31,
	2003	2002	2001
Sales of oil and gas production, net of production costs	$(1,674,000)	(1,005,000)	(1,775,000)
Net changes in prices and production costs	6,530,000	7,450,000	(4,205,000)
Revisions of previous quantity estimates	752,000	1,276,000	(1,693,000)
Accretion of discount	(3,186,000)	(4,037,000)	(2,971,000)
	$ 2,422,000	3,684,000	(10,644,000)

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

F-14

4.1	Form of Limited Partnership Agreement (incorporated by reference to Appendix A to Form S-1, SEC File No. 333-41977, and Rule 424 final prospectus, dated June 19 1998, of PDC 2000 Drilling Program, filed with the SEC on June 30, 1998).
14	Code of Ethics of Petroleum Development Corporation (incorporated by reference to the posted code on the web site of Petroleum Development Corporation at www.petd.com).
31.1	Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership.
31.2	Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership.
32.1	Certification of Chief Executive Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership under Title 18 United States Code section 1350.
32.2	Certification of Chief Financial Officer of Petroleum Development Corporation, the managing general partner of the Limited Partnership under Title 18 United States Code section 1350.

	December 31,
	2003	2002	2001
Lease acquisition costs	$ 460,141	460,141	460,141
Intangible development costs	16,510,178	16,510,178	16,510,178
Well equipment	3,917,618	3,917,618	3,917,618
Impairment charge	(10,764,226)	(10,764,226)	(10,764,226)
Capitalized asset retirement cost	22,568	-	-
	$ 10,146,279	10,123,711	10,123,711