CONFORMED COPY

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

West Virginia

(State or other jurisdiction of

incorporation or organization)

20-0547582

(I.R.S. Employer

Identification No.)

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 No X

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

PDC 2004-D Limited Partnership ("the Partnership") is a limited partnership formed on September 9, 2004 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 September 9, 2004, the Partnership has been engaged in onshore, domestic oil and natural gas exploration exclusively in the Rocky Mountain Region. A total of 27 limited partners contributed initial capital of $747,376 and a total of 1,084 additional general partners contributed initial capital of $34,251,651 and PDC (Managing General Partner) contributed $7,738,652 in capital as a participant in accordance with contribution provisions of the Limited Partnership Agreement (the Agreement).

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.

The Partnership has no employees, however, PDC has approximately 120 employees which include a staff of geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership's operations.

The Partnership participated in the drilling of approximately forty-four gross wells, (43.94 net wells), 17 in the fourth quarter of 2004 and 27 in the first quarter of 2005, and will continue to operate and produce its forty-four gross productive wells. At March 31, 2005, the Partnership does not have unexpended initial capital and no additional drilling activity is planned.

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 has had no sales in 2004.

The Partnership competes in marketing its gas and oil 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 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 $84,850 in 2004 to comply with federal and state 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.

The Partnership commenced drilling in the fourth quarter of 2004. As of December 31, 2004 the Partnership had 17 wells drilled and an additional 27 wells (all of which were productive) drilled as of March 31, 2005. All Partnership wells to date are development wells and drilling activity was substantially completed by March 31, 2005.

See "Management's Discussion and Analysis" on page 5 for Partnership production.

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

The Partnership has a total of 17 gross productive wells (16.97 net wells) all of which are located in Colorado.

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.

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.

The Managing General Partner as driller/operator is not party to any legal action that it believes would have a materially adverse affect to the Managing General Partner's or Partnership's business, financial condition, results of operations or liquidity.

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

At December 31, 2004, PDC 2004-D Limited Partnership had one Managing General Partner, 27 Limited Partners who fully paid for 37.37 units at $20,000 per unit of limited partnership interests and a total of 1,084 Additional General Partners who fully paid for 1,712.58 units at $20,000 per unit of additional general partnership interests. 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.

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

The Partnership was funded on September 9, 2004 with initial Limited and Additional General Partner contributions of $34,999,027 and the Managing General Partner's cash contribution of $7,738,652 in accordance with the Agreement. After payment of syndication costs of $3,519,432 and a one-time management fee to the managing general partner of $524,986, the Partnership had available cash of $38,693,262 for Partnership activities.

The Partnership began exploration and development activities subsequent to the funding of the Partnership and completed these activities by March 31, 2005. Seventeen had been drilled by December 31, 2004 and twenty-seven in 2005. No additional wells will be drilled.

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

In accordance with the Partnership agreement, a one-time management fee equal to 1 1/2% of investors' subscriptions was charged to the Partnership in the amount of $524,986 by the Managing General Partner. This fee was paid by the Partnership to the Managing General Partner of the Partnership upon funding of the Partnership.

The Partnership's revenues from oil and natural gas sales will be affected by changes in prices. As a result of changes in federal regulations, gas prices are highly dependent on the balance between supply and demand. The Partnership's gas sales prices are subject to increase and decrease based on various market sensitive indices.

Certain accounting policies are very important to the portrayal of Partnership's financial condition and results of operations and requires 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 accounting policies" in our financial statements and related notes. The Partnership's critical accounting policies and estimates are as follows:

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month to three years. Virtually all of the Managing General Partner's contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Managing General Partner believes that the pricing provisions of its natural gas contracts are customary in the industry.

The Managing General Partner currently uses the "Net-Back" method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner's customers and reflected in the wellhead price.

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The partnership does not refine any of its oil under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

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 Partnership would estimate 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 Partnership 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.

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.

Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, are capitalized.

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

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

Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value, is credited or charged to income. Upon sale of a partial unit of property, the proceeds are credited to accumulated depreciation and depletion.

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

The Managing General Partner will utilize commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its oil and natural gas sales and marketing activities. These instruments consist of natural gas futures contracts and option contracts for 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 Managing General Partner will receive for the volume to which the hedge relates. As a result, while these hedging arrangements are structured to reduce Partnership's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Partnership might otherwise have received from price changes associated with the hedged commodity. The Partnership's policy prohibits the use of natural gas future and option contracts for speculative purposes.

There are no hedge contracts outstanding as of December 31, 2004 related to oil or natural gas production.

The average NYMEX closing price for natural gas for the year 2004 was $6.14 per Mmbtu. The average NYMEX closing price for oil for the year 2004 was $41.44 per bbl. The average CIG closing price for natural gas for the year 2004 was $5.17 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.

As the information above incorporates only those exposures that exist at December 31, 2004, 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.

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.

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.

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 2004 has been filed with the Securities and Exchange Commission.

Although the Partnership has no Code of Ethics, Petroleum Development Corporation, the Managing General Partner of the Partnership, has a Code of Ethics that applies to its senior executive officers. The Code of Ethics is posted on the website of Petroleum Development Corporation at www.petd.com.

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

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 during the period ended from September 9, 2004 (date of iInception) to December 31, 2004.

* Consists of broker dealer commission paid to PDC Securities Incorporated (100% subsidiary of the Managing General Partner and Dealer Manager of the drilling program) which was reallowed or paid to the Soliciting Broker Dealers of the drilling program.

For the period from September 9, 2004 (date of inception) to December 31, 2004, the Partnership paid KPMG LLP $7,350 for professional services for the audit of the partnership's financial statement in its form 10-K and review of financial statements included in the Partnership's 10-Q's and $1,000 for income tax services.

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.

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.

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.

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:

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.

We have audited the accompanying balance sheet of PDC 2004-D Limited Partnership (a West Virginia limited partnership) as of December 31, 2004, and the related statements of operations, partners' equity, and cash flows for the period from September 9, 2004 (date of inception) to December 31, 2004. 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit 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 statement. 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 audit provides 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 2004-D Limited Partnership as of December 31, 2004, and the results of its operations and its cash flows for the period from September 9, 2004 (date of inception) to December 31, 2004, in conformity with U.S. generally accepted accounting principles.

	Limited and Additional General Partners	Managing General Partner	Total
Partners' initial capital contributions	$34,999,027	7,738,652	42,737,679
Syndication costs	(3,519,432)	-	(3,519,432)
Net (loss) income	(504,829)	5,039	(499,790)

Balance December 31, 2004	$30,974,766	7,743,691	38,718,457

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of PDC 2004-D Limited Partnership (the Partnership). The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities. Petroleum Development Corporation ("PDC") serves as managing general partner of the Partnership.

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 which were determined at year end by an independent petroleum engineer, Wright & Company, Inc. If a determination is made that an exploratory well has not discovered economically producible reserves, then its costs are expensed as dry hole costs.

As of December 31, 2004, the Partnership signed a turnkey drilling agreement and paid drilling advances of $38,693,262 to Petroleum Development Corporation, Managing General Partner, for the drilling of the Partnership wells, leases and equipment. There were 17 wells drilled as of December 31, 2004. The Partnership had drilled an additional 27 wells (all of which were productive) as of March 31, 2005. Drilling activity was completed by March 31, 2005.

The Managing General Partner currently uses the "Net-Back" method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the managing General Partner's customers and reflected in the wellhead price.

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable. The partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production. The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

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.

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.

The Partnership was organized as a limited partnership on September 9, 2004 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 Rocky Mountain Region.

Purchasers of partnership units subscribed to and fully paid for 37.37 units of limited partner interests and 1,712.58 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.

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.

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 period from September 9, 2004 (date of inception) to December 31, 2004.

	Period from September 9, 2004 (date of inception) to December 31, 2004
Drilling and completion costs	$38,693,262
Syndication costs *	3,519,432
Management fee	524,986
Tax return preparation	7,510
Direct administrative cost	4,545

*Consists of broker dealer commission paid to PDC Securities Incorporated (100% subsidiary of the Managing General Partner and Dealer manger of the drilling program) which was reallowed or paid to the Soliciting Broker Dealers of the drilling program.

The table below 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.

(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 1-1/2% 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 their direct costs incurred by the Managing General Partner on behalf of the Partnership.

(5) 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) The allocation of profits, losses and cash distributions of the Managing General Partner might be increased, and the allocation of profits, losses, and cash distributions of the Investor Partners might be decreased in the event that the Managing General Partner were to invest more than the Managing General Partner's minimum required Capital Contribution to cover tangible equipment and lease costs. The Managing General Partner will pay for the Partnership's share of all Leases and tangible well equipment. The entire Capital Contribution of the Investor Partners, after payment of brokerage commissions, due diligence reimbursement, and the Management Fee, will be utilized to pay for intangible drilling costs. In the event that the Intangible Drilling Costs exceed the funds of the Investor Partners available for payment of Intangible Drilling Costs (herein "excess IDC"), a portion of the Capital Contribution of the Managing General Partner may be used to pay such excess IDC. If the cost of Leases and tangible well equipment were to exceed the Managing General Partner's Capital Contribution of approximately 22% of the aggregate Capital Contribution of the Investor Partners, then the Managing General Partner will increase its Capital Contribution to fund such additional capital requirements and the Managing General Partner's allocation of profits, losses, and cash distributions will be increased to equal the percentage arrived at by dividing the Capital Contribution made by the Managing General Partner by the Capital Available for Investment; the allocation of the Investor Partners will be decreased accordingly.

(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 2004 there were no units purchased by PDC.

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 at December 31, 2004, are as follows:

The following additional costs were incurred for the Partnership's oil and gas activities:

Unevaluated oil and gas properties consist of payments to the managing general partner for drilling, completion, lease acquisition and gathering system costs on 27 wells drilled prior to March 31, 2005. All of the 27 wells drilled are productive.

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, 2004, the income tax basis of the Partnership's oil and gas properties was $7,738,652.

Proved oil and gas reserves of the Partnership have been estimated at December 31, 2004 by an independent petroleum engineer, Wright & Company, Inc. 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:

		Oil (Bbls)
		2004
Proved developed reserves:
	Beginning of year	-
	New Discoveries and extensions
	Rocky Mountain Region	179,000
	End of year	179,000

		Gas (MCF)
		2004
Proved developed reserves:
	Beginning of year	-
	New Discoveries and extensions
	Rocky Mountain Region	3,615,000
	End of year	3,615,000

(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.

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

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow 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.

	Period from September 9, 2004 (date of inception) to December 31, 2004
Oil and Gas Sales	$ -
Costs and Expenses	544,391
Net Loss	(499,790)
Allocation of Net Income (Loss):
Managing General Partner	5,039
Limited and Additional General Partners	(504,829)
Per Limited and Additional General Partner Unit	(288)
Total Assets	38,745,949
Cash Distributions:
Managing General Partner	-
Limited and Additional General Partners	-

4.1	Form of Limited Partnership Agreement (incorporated by reference to Appendix A to Form S-1, SEC File No. 333-111260 and Rule 424 final prospectus, dated May 25, 2004, of PDC 2004-2006 Drilling Program, filed with the SEC on May 28, 2004).
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). 9
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	Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation, the managing general partner of the limited partnership.

Signature	Title	Date



/s/ Steven R. Williams Steven R. Williams	Chairman, Chief Executive Officer, and Director	April 19, 2005

/s/ Darwin L. Stump Darwin L. Stump	Chief Financial Officer and Treasurer (principal financial and accounting officer)	April 19, 2005

/s/ Thomas E. Riley Thomas E. Riley	President and Director	April 19, 2005

/s/ Donald B. Nestor Donald B. Nestor	Director	April 19, 2005

/s/ Vincent F. D'Annunzio Vincent F. D'Annunzio	Director	April 19, 2005


Report of Independent Registered Public Accounting Firm	F-3
Balance Sheet - December 31, 2004	F-4
Statement of Operations - Period from September 9, 2004 (date of inception) to December 31, 2004	F-5
Statement of Partners' Equity - Period from September 9, 2004 (date of inception) to December 31, 2004	F-6
Statement of Cash Flows - Period from September 9, 2004 (date of inception) to December 31, 2004	F-7
Notes to Financial Statements	F-8

Assets

Current Assets:
Cash	$ 44,655
Total current assets	44,655

Oil and gas properties, successful efforts method (notes 3 and 5):	12,938,993
Less accumulated depreciation, depletion and amortization	-
Unevaluated properties	25,762,301
Total oil and gas properties	38,701,294
	$38,745,949

Liabilities and Partners' Equity

Current Liabilities:
Due to Managing General Partner	$ 100
Accrued expenses	19,360
Total current liabilities	19,460

Asset retirement obligation	8,032

Partners' equity	38,718,457
	$38,745,949

Drilling and completion costs	$38,693,262
Syndication costs*	3,519,432
Management fee	524,986
Tax return preparation	6,510
Direct administrative cost	4,545

Revenues:
Interest income	$ 44,601
Expenses (note 3):
Management fee	524,986
Independent audit fee	7,350
Tax return preparation	7,510
Direct administrative cost	4,545
	544,391
Net income (loss)	$(499,790)

Net income (loss) per limited and additional general partner unit	$ (288)

Cash flows from operating activities:
Net loss		$(499,790)
Adjustments to reconcile net loss to net cash used by operating activities:
Changes in operating assets and liabilities:
Increase in due to Managing General Partner		100
Increase in accrued expenses		19,360

	Net cash used by operating activities	(480,330)

Cash flows from investing activities:
Expenditures for oil and gas properties		(12,930,961)
Expenditures for unevaluated oil and gas properties		(25,762,301)

	Net cash used by investing activities	(38,693,262)

Cash flows from financing activities:
Limited and additional general partner contributions		34,999,027
Managing General Partner contribution		7,738,652
Syndication cost paid		(3,519,432)

	Net cash provided from financing activities		39,218,247


Net increase in cash			44,655
Cash at beginning of period			-
Cash at end of period			$ 44,655

Partnership Costs	Investor Partners(5)(6)	Managing General Partner(5)(6)
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	80%	20%
Sale of Productive Properties	80%	20%
Sale of Equipment	0%	100%
Sale of Undeveloped Leases	80%	20%
Interest Income	80%	20%

Lease acquisition costs	$618,800
Intangible development costs	9,516,125
Well equipment	2,796,036
Capital asset retirement cost	8,032
	$12,938,993

		Period from September 9, 2004 (date of inception) to December 31, 2004
Cost incurred:
Property acquisition costs	$ 618,800
Development costs	12,312,161
Unevaluated oil and gas properties	25,762,301
	$38,693,262

	As of December 31, 2004

Future estimated revenues		$ 29,029,000
Future estimated production costs		(6,730,000)
Future estimated development costs		(1,129,000)
Future net cash flows		21,170,000
10% annual discount for estimated timing of cash flows		(9,326,000)
Standardized measure of discounted future
estimated net cash flows		$11,844,000

	Period from September 9, 2004 (date of inception) to December 31, 2004

Extensions, discoveries, and improved recovery, less related cost	$8,239,000
Development costs incurred during the period	12,931,000
Less 10% discount	(9,326,000)
	$11,844,000