UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

Tx QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~March~~June 3130, 2010

£o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-51218

PDC 2004-A Limited Partnership

(Exact name of registrant as specified in its charter)


West Virginia	20-0545296
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

(303) 860-5800

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such files) and (2) has been subject to such filing requirements for the past 90 days.

Yes ~~RNo~~þNo £o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £o No £o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:

Large accelerated filer £o Accelerated filer £¨ Non-accelerated filer £¨ Smaller reporting company Rþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £¨ No Rþ

As of ~~March~~June 3130, 2010 the Partnership had 1,451.54 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page	~~Page~~
	PART I – FINANCIAL INFORMATION	~~PART I – FINANCIAL INFORMATION~~
Item 1.	Financial Statements (unaudited)	~~Financial Statements (unaudited)~~
	Condensed Balance Sheets (unaudited)	~~Condensed Balance Sheets (unaudited)~~2	2
	Condensed Statements of Operations (unaudited)	~~Condensed Statements of Operations (unaudited)~~3	3
	Condensed Statements of Cash Flows (unaudited)	~~Condensed Statements of Cash Flows (unaudited)~~4	4
	Notes to Unaudited Condensed Financial Statements	~~Notes to Unaudited Condensed Financial Statements~~5	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~13	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~Quantitative and Qualitative Disclosures About Market Risk~~24	19
Item 4T.	Controls and Procedures	~~Controls and Procedures~~24	19
	PART II – OTHER INFORMATION	~~PART II – OTHER INFORMATION~~
Item 1.	Legal Proceedings	~~Legal Proceedings~~25	20
Item 1A.	Risk Factors	~~Risk Factors~~25	20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~Unregistered Sales of Equity Securities and Use of Proceeds~~25	20
Item 3.	Defaults Upon Senior Securities	~~Defaults Upon Senior Securities~~25	20
Item 4.	[Removed and Reserved]	~~[Removed and Reserved]~~25	20
Item 5.	Other Information	~~Other Information~~25	20
Item 6.	Exhibits	~~Exhibits~~26	21
	SIGNATURES	~~SIGNATURES~~27	22

Index

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2004-A Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“PDC’s”) strategies, plans and objectives. However, these words are not the exclusive means of identifying forward-looking statements herein. ~~Although~~PDC ~~forward-looking~~now ~~statements~~conducts ~~contained~~business inunder ~~this report reflect~~ the ~~Managing~~name ~~General~~“PDC ~~Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner~~Energy. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:”

Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

changes in production volumes, worldwide demand, and commodity prices for natural gas and oil;

· ~~risks~~changes ~~incident~~in toestimates ~~the operation~~ of ~~natural~~proved ~~gas and oil wells~~reserves;

· ~~future~~the ~~production~~timing and ~~development~~extent ~~costs~~of the Partnership’s success in further developing and producing the Partnership’s natural gas and oil reserves;

the Managing General Partner’s ability to acquire drilling rigs, supplies and services at reasonable prices;

risks incident to the recompletion and operation of natural gas and oil wells;

future production and well recompletion costs;

the availability of Partnership future cash flows for investor distributions or funding of Well Recompletion Plan activities;

the timing and closing, if consummated, of the proposed merger of the Partnership with and into PDC’s wholly-owned subsidiary, DP 2004 Merger Sub, LLC;

the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary, DP 2004 Merger Sub, LLC to consummate the merger;

the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;

· the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America, or U.S.;

changes in environmental laws and the regulations and enforcement related to those laws;

the identification of and severity of environmental events and governmental responses to the events;

the effect of natural gas and oil derivatives activities;

conditions in the capital markets; and

losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission, (“or SEC”), on March 15, 2010, (“2009 Form 10-K”), and the Partnership’s other filings with the SEC and public disclosures. The Partnership cautions you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. ~~The~~Other than as required under the securities laws, the Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

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Index

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PDC 2004-A Limited Partnership
Condensed Balance Sheets
(unaudited)
	March 31, 2010			December 31, 2009*
	June 30,			December 31,
	2010			2009*
Assets
Current assets:
Cash and cash equivalents	$	157,965		$	157,965
Accounts receivable		~~270~~207,~~666~~012			220,647
Oil inventory		2615,~~347~~522			19,260
Due from Managing General Partner-derivatives		~~529~~452,~~525~~044			386,132
Due from Managing General Partner-other, net		~~307~~107,~~105~~927			276,800
Total current assets		1940,~~291,608~~470			1,060,804
Oil and gas properties, successful efforts method, at cost		32,335,~~313~~999			32,330,069
Less: Accumulated depreciation, depletion and amortization		(1516,~~866~~399,~~287~~328	)		(15,357,804	)
Oil and gas properties, net		1615,~~469~~936,~~026~~671			16,972,265
Due from Managing General Partner-derivatives		~~965~~916,~~385~~202			386,386
Other assets		3944,~~835~~579			35,157
Total noncurrent assets		1716,~~474~~897,~~246~~452			17,393,808
Total Assets	$	1817,~~765~~837,~~854~~922		$	18,454,612
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	29299,250		$	27,526
Due to Managing General Partner-derivatives		~~437~~355,~~163~~252			380,937
Total current liabilities		~~466~~654,~~413~~502			408,463
Due to Managing General Partner-derivatives		1954,~~184,687~~317			1,099,811
Asset retirement obligations		~~323~~328,~~533~~328			318,809
Total liabilities		1,~~974~~937,~~633~~147			1,827,083
Commitments and contingent liabilities
Partners' equity:
Managing General Partner		3,~~364~~185,~~087~~998			3,331,348
Limited Partners - 1,451.54 units issued and outstanding		1312,~~427~~714,~~134~~777			13,296,181
Total Partners' equity		1615,~~791~~900,~~221~~775			16,627,529
Total Liabilities and Partners' Equity	$	1817,~~765~~837,~~854~~922		$	18,454,612

________________________________

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-A Limited Partnership
Condensed Statements of Operations
(unaudited)
	Three months ended March 31,
	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010		2009
Revenues:
Natural gas and oil sales	$	~~842~~617,~~066~~369		$	~~452~~456,~~659~~989		$	1,459,435	$	909,648
Commodity price risk management gain (loss), net		~~908~~235,~~110~~547			(62546,~~035~~777	)		1,143,657		(608,812	)
Total revenues		1852,~~750,176~~916			~~390~~(89,~~624~~788	)		2,603,092		300,836
Operating costs and expenses:
Natural gas and oil production costs		~~152~~520,~~816~~006			~~158~~194,~~816~~233			672,822		353,049
Direct costs - general and administrative		3435,~~710~~463			67145,~~870~~134			70,173		213,004
Depreciation, depletion and amortization		~~508~~533,~~483~~041			~~464~~505,~~418~~788			1,041,524		970,206
Accretion of asset retirement obligations		4,~~724~~795			3,297			9,519		6,594
Total operating costs and expenses		~~700~~1,~~733~~093,305			~~694~~848,~~401~~452			1,794,038		1,542,853
Income (loss) from operations		1,049,443			(303,777	)
(Loss) income from operations		(240,389	)		(938,240	)		809,054		(1,242,017	)
Interest income		-			1312,~~130~~381			-		25,511
Net income (loss)	$	1,049,443		$	(290,647	)
Net (loss) income	$	(240,389	)	$	(925,859	)	$	809,054	$	(1,216,506	)
Net income (loss) allocated to partners	$	1,049,443		$	(290,647	)
Net (loss) income allocated to partners	$	(240,389	)	$	(925,859	)	$	809,054	$	(1,216,506	)
Less: Managing General Partner interest in net income (loss)		209,889			(58,129	)
Less: Managing General Partner interest in net (loss) income		(48,078	)		(185,172	)		161,811		(243,301	)
Net income (loss) allocated to Investor Partners	$	839,554		$	(232,518	)
Net (loss) income allocated to Investor Partners	$	(192,311	)	$	(740,687	)	$	647,243	$	(973,205	)
Net income (loss) per Investor Partner unit	$	578		$	(160	)
Net (loss) income per Investor Partner unit	$	(132	)	$	(510	)	$	446	$	(670	)
Investor Partner units outstanding		1,451.54			1,451.54			1,451.54		1,451.54

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-A Limited Partnership
Condensed Statements of Cash Flows
(unaudited)
	Three months ended March 31,
	Six months ended June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	1809,~~049,443~~054		$	(~~290~~1,~~647~~216,506	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		~~508~~1,~~483~~041,524			~~464~~970,~~418~~206
Accretion of asset retirement obligations		49,~~724~~519			36,~~297~~594
Unrealized (gain) loss on derivative transactions		(~~581~~766,~~290~~907	)		~~662~~1,~~149~~608,316
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(50,019	)		102,553
Decrease in accounts receivable		13,635			61,444
Increase in oil inventory		(7,087	)		(2,756	)
Decrease in oil inventory		3,738			17,988
Increase in other assets		(49,~~678~~422	)		(510,~~144~~288	)
Increase (decrease) in accounts payable and accrued expenses		1271,724			(3234,~~806~~382	)
Increase in due from Managing General Partner - other, net		(30,305	)		(98,347	)
Decrease in due from Managing General Partner - other, net		168,873			297,052
Net cash provided by operating activities		~~890~~1,~~995~~541,738			~~802~~1,~~717~~700,424
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(5,~~244~~930	)		(110,~~156~~208	)
Net cash used in investing activities		(5,~~244~~930	)		(110,~~156~~208	)
Cash flows from financing activities:
Distributions to Partners		(~~885~~1,~~751~~535,808	)		(~~800~~1,~~066~~688,723	)
Net cash used in financing activities		(885,751	)		(800,066	)
Net in financing activities		(1,535,808	)		(1,688,723	)
Net increase in cash and cash equivalents		-			1,~~495~~493
Cash and cash equivalents, beginning of period		157,965			156,423
Cash and cash equivalents, end of period	$	157,965		$	157,~~918~~916

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2004-A Limited Partnership was organized as a limited partnership on April 9, 2004, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of ~~oil and~~ natural gas and oil properties. Upon completion of the sale of Partnership units on April 30, 2004, the Partnership was funded and commenced its business operations. The Partnership owns natural gas and oil wells located in Colorado, and from the wells, the Partnership produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 33.34 units of limited partner interests and 1,418.20 units of additional general partner interests at $20,000 per unit. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a Nevada Corporation that now conducts business under the name “PDC Energy,” is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner” or “PDC”) and has a 20% Managing General Partner ownership in the Partnership. Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 20% to the Managing General Partner.

As of ~~March~~June 3130, 2010, there were 1,~~153~~152 Investor Partners. As of ~~March~~June 3130, 2010 the Managing General Partner has repurchased 5960.81 units of the total 1,451.54 outstanding units of Partnership interests from Investor Partners at an average price of $7,~~614~~563 per unit and, as a result, participates in the sharing of revenues, costs and cash distributions as both an investor partner and as the Managing General Partner.

The Managing General Partner, under the terms of the Drilling and Operating Agreement (the “D&O Agreement”), has full authority to conduct the Partnership’s business and actively manage the Partnership. The Partnership expects continuing operations of its ~~oil and~~ natural gas and oil properties until such time that athe ~~well~~Partnership’s iswells are depleted or ~~becomes~~become uneconomical to produce, at which time that well ~~will~~may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2055, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

InOn ~~the~~June ~~Managing~~7, ~~General~~2010, ~~Partner’s~~the ~~opinion~~Partnership, the ~~accompanying~~Managing ~~interim~~General ~~unaudited~~Partner ~~condensed~~and ~~financial~~its ~~statements~~wholly-owned ~~contain~~subsidiary, ~~all~~DP ~~adjustments~~2004 ~~(consisting~~Merger ofSub, ~~only~~LLC ~~normal~~(“DP ~~recurring~~Merger ~~adjustments~~Sub”), ~~necessary for~~ a ~~fair~~Delaware ~~presentation~~limited ofliability ~~the~~company, ~~Partnership’s~~entered ~~financial~~into ~~statements~~an ~~for~~agreement ~~interim~~and ~~periods~~plan inof ~~accordance~~merger ~~with~~(the ~~accounting~~“Merger ~~principles~~Agreement”) ~~generally accepted~~ in ~~the~~which ~~United~~PDC ~~States~~seeks ofto ~~America~~acquire ~~("U.S.~~the ~~GAAP")~~Partnership, ~~and~~subject ~~with~~to the ~~instructions~~vote toand ~~Form~~approval ~~10-Q~~of ~~and~~the ~~Article~~holders 10 of ~~Regulation~~a ~~S-X~~majority of the ~~SEC. Accordingly,~~limited ~~pursuant~~partnership tounits ~~such~~held ~~rules~~by ~~and~~Investor ~~regulations,~~Partners ~~certain~~of ~~notes~~the ~~and~~Partnership ~~other~~who ~~financial~~are ~~information~~not ~~included~~affiliated inwith ~~audited~~PDC ~~financial~~(“third-party ~~statements~~Investor ~~have been condensed or omitted~~Partners”). ~~The~~For more information ~~presented~~on inthe ~~this~~proposed ~~quarterly~~Merger ~~report~~Agreement, onsee ~~Form~~Note ~~10-Q~~3, ~~should~~Transactions bewith ~~read~~Managing inGeneral ~~conjunction~~Partner ~~with~~and ~~the~~Affiliates−Proposed ~~Partnership’s~~Merger ~~audited~~with ~~financial~~PDC ~~statements~~ and ~~notes~~DP ~~thereto~~2004 ~~included~~Merger inSub, ~~the~~LLC, ~~Partnership’s~~which ~~2009 Form 10-K~~follows. ~~The~~Pending ~~Partnership’s~~the ~~accounting~~outcome ~~policies~~of ~~are described in~~ the ~~Notes~~proposed toMerger ~~Financial~~Agreement, ~~Statements in~~ the ~~Partnership’s~~Managing ~~2009~~General ~~Form~~Partner ~~10-K and updated~~suspended, as ~~necessary, in this Form 10-Q. The results~~ of ~~operations~~July ~~for the three months ended March 31~~1, 2010, ~~and~~ the ~~cash~~opportunity ~~flows~~ for ~~the~~an ~~same~~individual ~~period,~~investor ~~are~~partner ~~not necessarily indicative of the results~~ to berequest ~~expected~~that ~~for~~PDC ~~the~~repurchase ~~full~~their ~~year~~respective orlimited ~~any~~partnership ~~other future period~~units.

~~The~~In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership'’s 2009 Form 10-K. The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2009 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the ~~year~~three and six months ended ~~December~~June 3130, ~~2009~~2010, asand ~~filed~~the ~~with~~cash flows for the ~~SEC~~six onmonths ~~March~~ended 15June 30, 2010, (“are not necessarily indicative of the ~~2009~~results ~~Form~~to ~~10-K”)~~be expected for the full year or any other future period.

The Managing General Partner has evaluated the Partnership’s activities subsequent to March 31, 2010 and has concluded that no material subsequent events have occurred that would require recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.

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Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to fair value measurements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying unaudited condensed financial statements.

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. This change will be effective for the Partnership’s financial statements issued for annual reporting periods beginning after December 15, 2010. The Partnership does not expect adoption of these changes to have a material effect on the Partnership’s financial statements and related disclosures.

Internal Control over Financial Reporting in Exchange Act Periodic Reports

On July 21, 2010, the enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act made permanent the SEC’s non-accelerated filer’s exemption, previously set to expire after December 15, 2010, from compliance with Section 404(b) of the Sarbanes-Oxley Act of 2002, or SOX. Therefore, as a non-accelerated filer, the Partnership is permanently exempted from the SOX requirement that SEC registrants provide an attestation report on the effectiveness of internal controls over financial reporting by the registrant’s external auditor.

Note 3−Transactions with Managing General Partner and Affiliates

Ongoing Partnership Business and Operations

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or “Due to Managing General Partner–derivatives,” in the case of net unrealized losses.

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item – Due from (to) Managing General Partner-other, net which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.

	March 31, 2010			December 31, 2009
	June 30,			December 31,
Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	251,297		$	281,922
	2010			2009
Commodity price risk management, realized gains		230,335			277,646
Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	221,702		$	281,922
Other (1)		(174,527	)		(282,768	)
Commodity Price Risk Management, Realized Gains		36,471			277,646
Total Due from Managing General Partner-other, net	$	307,105		$	276,800
Other (1)		(150,246	)		(282,768	)
Total Due from Managing General Partner-other, net	$	107,927		$	276,800

(1) All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner. The majority of these are operating costs or general and administrative costs which have not been deducted from distributions.

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for three months ended March 31, 2010 and 2009. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Natural gas and oil production costs” on the statements of operations.

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Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

	Three months ended March 31,
	2010		2009
Well operations and maintenance	$	89,810	$	103,690
Gathering, compression and processing fees		33,231		29,698
Direct costs - general and administrative		34,710		67,870
Cash distributions*		206,268		178,127

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for three and six months ended June 30, 2010 and 2009. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Natural gas and oil production costs” on the statements of operations.

*Cash distributions include $29,118 during the three months ended March 31, 2010, and $18,114 during the three months ended March 31, 2009, related to equity cash distributions on Investor Partner units repurchased by PDC. For additional disclosure regarding the Unit Repurchase Program, refer to Note 1, General and Basis of Presentation.

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009

Well operations and maintenance	$	451,297	$	133,635	$	541,107	$	237,325
Gathering, compression and processing fees		33,435		35,151		66,666		64,849
Direct costs - general and administrative		35,463		145,134		70,173		213,004
Cash distributions*		151,671		205,038		357,939		383,165

~~Note~~*Cash ~~4−Fair~~distributions ~~Value~~include ~~Measurements~~$21,660 and $50,778 during the three and six months ended June 30, 2010, respectively, and $27,307 and $45,421 during the three and six months ended June 30, 2009, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

~~Derivative~~Proposed ~~Financial~~Merger ~~Instruments. The~~with Partnership measures fair value based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s ~~own business interests~~ and ~~liabilities,~~DP as2004 ~~well~~Merger ~~as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses financial institutions~~Sub, who are also major lenders in PDC’s credit facility agreement, as counterparties to the Partnership’s derivative contracts. The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation as of March 31, 2010, the impact of non-performance risk on the fair value of the Managing General Partner’s derivative assets and liabilities was not significant. Validation of the Partnership’s contracts’ fair values are performed internally and while the Managing General Partner uses common industry practices to develop valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.LLC

On June 7, 2010, the Partnership, the Managing General Partner and DP Merger Sub, a wholly owned subsidiary of PDC, entered into the Merger Agreement subject to the vote and approval of the holders of a majority of the limited partnership units held by third-party Investor Partners as well as the satisfaction of other customary closing conditions.

The Merger Agreement has been approved by PDC’s Board of Directors (the “Board”) and by the Special Committee formed by the Board, comprised of four non-employee members of PDC’s Board, to represent the interests of the third-party Investor Partners holding limited partnership units. The Board, on behalf of PDC individually, and the Special Committee, on behalf of PDC in its capacity as the Partnership’s Managing General Partner, have determined that the merger is advisable and in the best interests of PDC and the Partnership, respectively, and reasonably believe that the merger is fair to PDC and the third-party Investor Partners in the Partnership, respectively.

Each member of the Special Committee, on behalf of PDC in its capacity as the Managing General Partner of the Partnership, has relied upon his own business judgment and analysis based on a variety of factors in addition to the financial analysis of an outside financial advisor with respect to the fairness to the third-party Investor Partners’ interests from a financial point of view of the consideration to be received by the third-party Investor Partners pursuant to the Merger Agreement. Also, the Special Committee retained its own legal counsel to advise it regarding the terms of the proposed merger. The Special Committee has recommended that the third-party Investor Partners vote for the limited partnership amendment and the Merger Agreement.

If approved by the third-party Investor Partners and completed, the merger will be retrospectively effective as of May 1, 2010, the separate existence of the Partnership will terminate and the third-party Investor Partner’s will receive a cash payment in the amount of $8,400 per limited partnership unit, less the sum of all per unit cash distributions made after June 30, 2010, and before the transaction closes. Additionally, DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity.

The Merger Agreement among the Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:

should all parties agree by mutual consent to terminate the agreement;

by any party thereto, should the proposed merger not occur by December 31, 2010;

by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;

- 7 -

Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

by any party thereto, should any suit or action be pending against parties to the agreement challenging the legality or any aspect of the merger transaction;

by the Special Committee, on behalf of the Partnership and prior to approval by third-party Investor Partners, should the Special Committee believe it has received a superior offer that is more favorable to the third-party Investor Partners; or

by PDC or the Partnership, should either PDC or the Partnership fail to perform its obligations under the Merger Agreement and such failure has a non-curable material adverse effect on the PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

Closing of the merger is conditioned on approval by a majority vote of third-party Investor Partners on both proposals to (1) amend the limited partnership agreement to expressly provide third-party Investor Partners the right to approve merger transactions and (2) approve the Merger Agreement, described above. On July 8, 2010, the Partnership filed a Preliminary Proxy Statement on Schedule 14A relating to the merger with the SEC. Although there is no assurance of the likelihood or timing of the merger transaction, upon clearance by the SEC, a definitive proxy statement will be mailed to the Partnership’s limited partners. After approval by a majority vote of third-party Investor Partners and the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware, no additional filing or registration with, notification to, or authorization, consent or approval of, any governmental entity will be required in connection with the execution and delivery of the Merger Agreement by the Partnership, PDC or DP Merger Sub or the consummation by the Partnership, PDC or DP Merger Sub of the transactions contemplated thereby. Following consummation of the merger, the Partnership will no longer be required to file reports with the SEC, and the third-party Investor Partners will no longer participate in the Partnership’s future earnings or growth.

Regardless of whether the merger is consummated, all costs and expenses incurred by PDC, the Partnership and DP Merger Sub in connection with the merger agreement, shall be paid by PDC.

Note 4−Fair Value Measurements

Derivative Financial Instruments. The Partnership measures fair value based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in PDC’s credit facility agreement, as counterparties to the Partnership’s derivative contracts. The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, as of June 30, 2010, the impact of nonperformance risk on the fair value of the Partnership’s derivative assets and liabilities was not significant. Validation of the Partnership’s contracts’ fair values are performed internally and while the Managing General Partner uses common industry practices to develop valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

- 8 -

Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

The following table presents, by hierarchy level, the Partnership’s derivative financial instruments, including both current and non-current portions measured at fair value.

	Quoted Prices in Active Markets			Significant Unobservable Inputs
	(Level 1)			(Level 3)			Total
As of December 31, 2009
Assets:
Commodity based derivatives	$	389,241		$	383,277		$	772,518
Total assets		389,241			383,277			772,518
Liabilities:
Commodity based derivatives		(7,069	)		(79,840	)		(86,909	)
Basis protection derivative contracts		-			(1,393,839	)		(1,393,839	)
Total liabilities		(7,069	)		(1,473,679	)		(1,480,748	)
Net asset (liability)	$	382,172		$	(1,090,402	)	$	(708,230	)
As of March 31, 2010
As of June 30, 2010
Assets:
Commodity based derivatives	$	1,~~367~~223,~~498~~769		$	~~127~~144,~~412~~477		$	1,~~494~~368,~~910~~246
Total assets		1,~~367~~223,~~498~~769			~~127~~144,~~412~~477			1,~~494~~368,~~910~~246
Liabilities:
Commodity based derivatives		-			(5330,~~703~~411	)		(5330,~~703~~411	)
Basis protection derivative contracts		-			(1,~~568~~279,~~147~~158	)		(1,~~568~~279,~~147~~158	)
Total liabilities		-			(1,~~621~~309,~~850~~569	)		(1,~~621~~309,~~850~~569	)
Net asset (liability)	$	1,~~367~~223,~~498~~769		$	(1,~~494~~165,~~438~~092	)	$	~~(126~~58,~~940~~677	)

The following table presents the changes of the Partnership’s Level 3 derivative financial instruments measured on a recurring basis:

	Three months ended
	Six months ended
	March 31, 2010
	June 30, 2010
Fair value, net liability, as of December 31, 2009	$	(1,090,402	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		~~(77~~157,~~216~~813	)
Settlements		(~~326~~232,~~820~~503	)
Fair value, net liability, as of March 31, 2010	$	(1,494,438	)
Fair value, net liability, as of June 30, 2010	$	(1,165,092	)
Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2010 included in statement of operations line item:
Change in unrealized gains (losses) relating to assets (liabilities) still held as of June 30, 2010 included in statement of operations line item:
Commodity price risk management, net	$	~~(124~~98,~~953~~493	)

See Note 5, Derivative Financial Instruments, for additional disclosure related to the Partnership’s derivative financial instruments.

Non-Derivative Assets and Liabilities. The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

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Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

Note 5−Derivative Financial Instruments

As of ~~March~~June 3130, 2010, the Partnership had derivative instruments, comprised of commodity collars, commodity fixed-price swaps and basis protection swaps, in place for a portion of its anticipated production through 2013 for a total of 1,~~204~~105,~~547~~925 MMbtu of natural gas and 108,~~300~~110 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

The following table summarizes the ~~location~~line item and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets.

					Fair Value	~~Fair Value~~
Derivative instruments not designated as hedge (1):				Balance Sheet Line Item		March 31, 2010				December 31, 2009
			Balance Sheet		June 30,				December 31,
Derivative Assets:		Current
Derivative instruments not designated as hedge (1):			Line Item		2010				2009
		Commodity contracts		Due from Managing General Partner-derivatives		$	529,525			$	386,132
Derivative Assets:	Current
		Non Current
	Commodity contracts		Due from Managing General Partner-derivatives		$	452,044			$	386,132
		Commodity contracts		Due from Managing General Partner-derivatives			965,385				386,386
	Non Current
Total Derivative Assets						$	1,494,910			$	772,518
	Commodity contracts		Due from Managing General Partner-derivatives			916,202				386,386
Derivative Liabilities:		Current
Total Derivative Assets					$	1,368,246			$	772,518
		Commodity contracts		Due to Managing General Partner-derivatives		$	(12,793	)		$	(31,423	)
Derivative Liabilities:	Current
		Basis protection contracts		Due to Managing General Partner-derivatives			(424,370	)			(349,514	)
	Commodity contracts		Due to Managing General Partner-derivatives		$	(13,986	)		$	(31,423	)
		Non Current
	Basis protection contracts		Due to Managing General Partner-derivatives			(341,266	)			(349,514	)
		Commodity contracts		Due to Managing General Partner-derivatives			(40,909	)			(55,486	)
	Non Current
		Basis protection contracts		Due to Managing General Partner-derivatives			(1,143,778	)			(1,044,325	)
	Commodity contracts		Due to Managing General Partner-derivatives			(16,426	)			(55,486	)
Total Derivative Liabilities						$	(1,621,850	)		$	(1,480,748	)
	Basis protection contracts		Due to Managing General Partner-derivatives			(937,891	)			(1,044,325	)
Total Derivative Liabilities					$	(1,309,569	)		$	(1,480,748	)

(1) As of ~~March~~June 3130, 2010 and December 31, 2009, none of the Partnership’s derivative instruments were designated as hedges.

~~The~~- ~~following~~10 ~~table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three months ended March 31, 2010 and 2009.~~-

	Three months ended March 31,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total
Commodity price risk management, net
Realized gains	$	302,726		$	24,094	$	326,820	$	495,526		$	104,588		$	600,114
Unrealized (losses) gains		(302,726	)		884,016		581,290		(495,526	)		(166,623	)		(662,149	)
Total commodity price risk management gain (loss), net	$	-		$	908,110	$	908,110	$	-		$	(62,035	)	$	(62,035	)

Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Partnership to credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts. To date, the Partnership has experienced no counterparty default losses.

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Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three and six months ended June 30, 2010 and 2009.

	Three months ended June 30,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Losses For the Current Period			Total

Commodity price risk management, net
Realized gains (losses)	$	45,542		$	4,388	$	49,930	$	429,310		$	(29,920	)	$	399,390
Unrealized (losses) gains		(45,542	)		231,159		185,617		(429,310	)		(516,857	)		(946,167	)
Total commodity price risk management gain (loss), net	$	-		$	235,547	$	235,547	$	-		$	(546,777	)	$	(546,777	)

	Six months ended June 30,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total

Commodity price risk management, net
Realized gains	$	196,747		$	180,003	$	376,750	$	796,234		$	203,270		$	999,504
Unrealized (losses) gains		(196,747	)		963,654		766,907		(796,234	)		(812,082	)		(1,608,316	)
Total commodity price risk management gain (loss), net	$	-		$	1,143,657	$	1,143,657	$	-		$	(608,812	)	$	(608,812	)

Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Partnership to the risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts. To date, the Partnership has experienced no counterparty defaults.

Note 6−Commitments and Contingencies

Stormwater Permit. On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are oil and gas companies operating in the Piceance Basin of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among the users of the road based upon their respective usage. The Partnership has 11 wells in this region. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records.Environmental

~~Derivative~~Due ~~Contracts. The~~to ~~Partnership~~the isnature ~~exposed~~of tothe natural gas and oil ~~price~~business, ~~fluctuations~~the onPartnership ~~underlying~~is ~~sales~~exposed ~~contracts~~to ~~should~~environmental ~~the~~risks. The ~~counterparties~~Managing General Partner has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s ~~derivative~~environmental ~~instruments~~risk ~~not~~profile. Liabilities ~~perform~~are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. ~~Nonperformance~~As isof ~~not~~June ~~anticipated~~30, 2010, the Partnership had accrued an environmental remediation liability included in Balance Sheet line item captioned “Accounts payable and accrued expenses”. ~~Neither~~This accrual represents costs estimated to be incurred in addition to normal recurring environmental-related expenditures which have been incurred and recorded at June 30, 2010. During the second quarter of 2010, the Managing General Partner, ~~nor~~identified existing ground contamination on one well site containing three of the Partnership's wells. The accrual of approximately $0.3 million is the estimated cost attributable to the Partnership, ~~have~~based ~~had~~principally on third party bids, to remediate the ground contamination. The Managing General Partner is not aware of any ~~counterparty~~environmental ~~default~~claims ~~losses~~existing as of June 30, 2010, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past contamination or non-compliance with environmental laws will not be discovered on the Partnership’s properties.

- 1011 -

Index

PDC 2004-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

On December 8, 2008, the Managing General Partner received a Notice of Violation/Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are oil and gas companies operating in the Piceance Basin of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among the users of the road based upon their respective usage. The Partnership has 11 wells in this region. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records.

Derivative Contracts

The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and oil. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations by utilizing derivative instruments. Should the counterparties to the Managing General Partner's derivative instruments not perform, the Partnership's exposure to market fluctuations in commodity prices would increase significantly. The Managing General Partner and the Partnership have had no counterparty defaults.

- 12 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Partnership Overview

PDC 2004-A Limited Partnership engages in the development, production and sale of ~~oil and~~ natural gas and oil. The Partnership began ~~oil~~natural gas and ~~gas~~oil operations in April 2004 and currently operates 37 gross (3231.57 net) wells located in the Rocky Mountain Region in the state of Colorado. Of the Partnership’s total well count, 36 are producing and one Wattenberg Field well is not producing due to mechanical problems. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership ~~through~~in accordance with the D&O Agreement, ~~may~~is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component. The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells, may provide for additional reserve development and production.

~~The~~Well ~~Partnership’s~~Recompletion wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells, may provide for additional reserve development and production. The Managing General Partner has developed a plan to initiate recompletion activities during 2010. This plan includes notifying investor partners that in October 2010, funds to begin these recompletions will be withheld from future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities. The funds retained which are necessary for the Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not recompleted due to an unfavorable general economic climate or unfavorable commodity price environment, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number of recompletions and the timing of recompletions will be based on the availability of cash withheld from distributions and continued favorable geological information. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. The Managing General Partner will continue to evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion. Plan

~~PDC~~The Managing General Partner has developed a plan to initiate recompletion activities during 2011. This plan includes notifying investor partners that in October 2010, ~~the~~funds ~~managing~~to ~~general~~begin ~~partner~~these recompletions may be withheld from future distributable cash flows of ~~various~~the ~~public~~Partnership ~~limited~~resulting ~~partnerships,~~from ~~has~~both ~~disclosed~~current ~~its~~production ~~intention~~and any increased production due to ~~pursue~~recompletion activities. The funds retained that are necessary for the ~~acquisition~~Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the ~~remaining~~Partnership’s ~~third~~Wattenberg ~~party~~wells ~~investor~~are ~~interests~~not recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the ~~limited~~number ~~partnerships~~of ~~which~~recompletions ~~PDC~~and ~~has~~the ~~sponsored,~~timing ~~including~~of ~~PDC~~recompletions ~~2004-A~~will ~~Limited~~be based on the availability of cash withheld from Partnership distributions. ~~These~~The ~~purchases,~~Managing ~~which~~General ~~PDC~~Partner ~~has~~believes ~~stated~~that, itbased ~~anticipates~~on ~~might~~projected ~~occur~~recompletion ~~over~~costs ~~the~~and ~~next~~projected ~~three~~cash ~~years~~withholding, all partnership recompletions will be ~~subject~~completed towithin ~~PDC~~a five year period. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. This Partnership potentially has 24 well recompletion opportunities. Total withholding for these activities from the Partnership’s ~~having~~distributable ~~sufficient~~cash ~~available~~flows ~~capital~~is estimated to total between $3.6 million and $4.8 million. The Managing General Partner will re-evaluate the ~~approval~~feasibility byof acommencing ~~majority~~any or all of ~~the~~these ~~investors’~~recompletion ~~partnership~~opportunities ~~interests,~~based ~~excluding~~on ~~partnership~~engineering ~~interest~~data ~~owned~~and bya ~~PDC,~~favorable ofcommodity ~~each~~price ~~respective~~environment ~~limited~~in ~~partnership~~order to maximize the financial benefit of the recompletion.

IfImplementation aof ~~purchase~~the ~~offer~~Well ~~from~~Recompletion ~~PDC~~Plan would reduce or eliminate Partnership distributions to investors while the work is ~~proposed~~being conducted and ~~approved~~paid byfor. Depending aupon ~~majority~~the level of ~~the~~withholding ~~Partnerships’~~and ~~unaffiliated~~the ~~limited~~results ~~partners~~of operations, it ~~would~~is ~~result~~possible that investors could have taxable income from the Partnership without any corresponding distributions in athe ~~liquidating~~future. Investor ~~cash~~Partners ~~distribution~~are urged to consult a tax advisor to determine all ~~partners~~of the relevant federal, state and ~~termination~~local tax consequences of the ~~existence~~Well Recompletion Plan. The above discussion is not intended as a substitute for careful tax planning, and third-party Investor Partners should depend upon the advice of their own tax advisors concerning the ~~Partnership~~effects of the Well Recompletion Plan.

-Proposed 11Merger -with PDC and DP 2004 Merger Sub, LLC

- 13 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The Merger Agreement among the Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:

should all parties agree by mutual consent to terminate the agreement;

by any party thereto, should the proposed merger not occur by December 31, 2010;

by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;

by any party thereto, should any suit or action be pending against parties to the agreement challenging the legality or any aspect of the merger transaction;

- 14 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Regardless of whether the merger is consummated, all costs and expenses incurred by PDC, the Partnership and DP Merger Sub in connection with the merger agreement, shall be paid by PDC.

The exchange by a third-party Investor Partner of limited partnership units for cash pursuant to the merger will be a taxable transaction for U.S. federal income tax purposes. The effects of the merger may be different for each investor partner. Third-party Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the potential Merger Agreement. The above discussion is not intended as a substitute for careful tax planning, and third-party Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the potential merger.

On July 1, the Managing General Partner suspended the opportunity for an individual third-party Investor Partner to request that PDC repurchase their respective limited partnership units under the terms of the program, pending the outcome of the proposed Merger Agreement.

The Managing General Partner, PDC, can provide no assurance that the proposed merger of the Partnership with and into PDC’s wholly-owned subsidiary DP Merger Sub, will be approved by third-party Investor Partners or that the other conditions to the completion of the merger will be satisfied or that the merger will ever be consummated. If the merger is not completed, the anticipated third-party Investor Partner merger benefits that include unit liquidity and elimination of Schedule K-1 tax reports in the Partnership will not be realized and the Partnership will continue the existing business plan to optimally develop and cost-effectively operate the Partnership’s natural gas and oil reserves. This plan would encompass the finalization and implementation of the Well Completion Plan, more fully outlined above.

Partnership Operating Results Overview

Natural gas and oil sales increased 60% or $0.5 million for the first six months of 2010 compared to the first six months of 2009, even though production volumes decreased 5% period-to-period. This increase was driven primarily by the improved commodity price environment and the increase in the Partnership’s oil production as a percentage of total production. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.18 for the current year period compared to $3.07 for the same period a year ago. Realized derivative gains from natural gas and oil sales contributed an additional $1.33 per Mcfe or $0.4 million to the first six months of 2010 total revenues. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased marginally to $6.51 for the current year six months from $6.44 for the same prior year period.

Natural gas and oil production and well operations costs increased by $0.3 million for the six month period ending June 30, 2010, compared to the same prior year period. The $0.3 million increase is primarily the result of accruing for environmental remediation costs during the period.

- 15 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

The following table presents selected information regarding the Partnership’s results of operations.

	Three months ended March 31,
	Three months ended June 30,							Six months ended June 30,
	2010		2009		Change			2010		2009		Change
Number of producing wells (end of period)		36		36		-			36		36		-
Production: (1)
Production (1)
Natural gas (Mcf)		120,~~094~~774		~~120~~138,~~049~~144		0-13	%		240,868		258,193		-7	%
Oil (Bbl)		3,~~246~~602		23,~~852~~525		142	%		6,848		6,377		7	%
Natural gas equivalents (Mcfe) (2)		~~139~~142,~~570~~386		~~137~~159,~~161~~294		2-11	%		281,956		296,455		-5	%
Mcfe per day		1,551		1,524
Natural Gas and Oil Sales
Natural Gas and Oil Sales
Natural gas	$	361,703	$	275,948		31	%	$	969,273	$	626,125		55	%
Natural gas	$	607,570	$	350,177		74	%
Oil		255,666		181,041		41	%		490,162		283,523		73	%
Oil		234,496		102,482		129	%
Total natural gas and oil sales	$	617,369	$	456,989		35	%	$	1,459,435	$	909,648		60	%
Total natural gas and oil sales	$	842,066	$	452,659		86	%
Realized Gain on Derivatives, net
Realized Gain on Derivatives, net (3)
Natural gas	$	17,148	$	322,665		-95	%	$	313,313	$	806,331		-61	%
Natural gas	$	296,165	$	483,666		-39	%
Oil		32,782		76,725		-57	%		63,437		193,173		-67	%
Oil		30,655		116,448		-74	%
Total realized gain on derivatives, net	$	49,930	$	399,390		-87	%	$	376,750	$	999,504		-62	%
Total realized gain on derivatives, net	$	326,820	$	600,114		-46	%
Average Selling Price (excluding realized gain on derivatives)
Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	2.99	$	2.00		50	%	$	4.02	$	2.43		66	%
Natural gas (per Mcf)	$	5.06	$	2.92		73	%
Oil (per Bbl)		70.98		51.36		38	%		71.58		44.46		61	%
Oil (per Bbl)		72.24		35.93		101	%
Natural gas equivalents (per Mcfe)		4.34		2.87		51	%		5.18		3.07		69	%
Natural gas equivalents (per Mcfe)		6.03		3.30		83	%
Average Selling Price (including realized gain on derivatives)
Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.14	$	4.33		-28	%	$	5.32	$	5.55		-4	%
Natural gas (per Mcf)	$	7.53	$	6.95		8	%
Oil (per Bbl)		80.08		73.13		10	%		80.84		74.75		8	%
Oil (per Bbl)		81.69		76.76		6	%
Natural gas equivalents (per Mcfe)		4.69		5.38		-13	%		6.51		6.44		1	%
Natural gas equivalents (per Mcfe)		8.37		7.68		9	%
Average Lifting Cost (per Mcfe) (3)	$	3.65	$	1.22		199	%	$	2.39	$	1.19		101	%
Average Lifting Cost (per Mcfe) (4)	$	1.09	$	1.16		-6	%
Operating costs and expenses
Operating costs and expenses:
Direct costs - general and administrative	$	35,463	$	145,134		-76	%	$	70,173	$	213,004		-67	%
Direct costs - general and administrative	$	34,710	$	67,870		-49	%
Depreciation, depletion and amortization	$	533,041	$	505,788		5	%	$	1,041,524	$	970,206		7	%
Depreciation, depletion and amortization	$	508,483	$	464,418		9	%
Cash distributions	$	650,057	$	888,657		-27	%	$	1,535,808	$	1,688,723		-9	%
Cash distributions	$	885,751	$	800,066		11	%

_______________

(1)

Production is determined by multiplying the gross production volume of properties in which the Partnership has an interest by the percentage of the leasehold or other property interest the Partnership owns.

(2)

A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.

(3) ~~Amounts~~Production costs represent ~~realized~~natural ~~derivative~~gas ~~gains~~and ~~related~~oil tooperating ~~natural~~expenses ~~gas~~which ~~and~~include ~~oil~~production ~~sales~~taxes.

(4) Production costs represent natural gas and oil operating expenses which include production taxes.

- 12 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations:

Bbl – One barrel or 42 U.S. gallons liquid volume

MBbl – One thousand barrels

Mcf – One thousand cubic feet

MMcf – One million cubic feet

Mcfe – One thousand cubic feet of natural gas equivalents

MMcfe – One million cubic feet of natural gas equivalents

MMbtu – One million British Thermal Units

- 16 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Natural Gas and Oil Sales

~~The~~Six ~~$0.4~~months ~~million,~~ended orJune ~~86%~~30, ~~increase in total sales in for the~~ 2010 ~~three month period~~ as compared to ~~the~~six ~~same~~months ~~period~~ended inJune ~~2009 was primarily a reflection of the significantly higher average sales price per Mcfe~~30, of 83% which was supported by stable Partnership production volumes of approximately 140,000 Mcfe during the two comparable periods. Average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.03 for the current year quarter compared to $3.30 for the same quarter a year ago.2009

The $0.5 million, or 60% increase in ~~natural~~total ~~gas~~sales ~~revenues~~for ofthe ~~74%~~2010 ~~contrasts~~six month period as compared to the ~~more~~prior ~~significant~~year ~~increase~~period, inwas ~~oil~~primarily ~~revenues~~a reflection of ~~129%.~~the ~~The~~significantly ~~Partnership’s~~higher ~~oil~~average ~~revenue~~sales ~~increase~~price per Mcfe of 69%, which was ~~bolstered~~partially offset by ~~improved~~a ~~average~~production ~~oil~~volume ~~sales~~decrease ~~prices~~of ~~(101~~5%). The asaverage ~~compared~~sales toprice per Mcfe, excluding the ~~more~~impact ~~moderate,~~of ~~yet~~realized ~~significant~~derivative gains, ~~increase~~was in$5.18 ~~natural~~for ~~gas~~the ~~sales~~current ~~prices~~year ~~(73%)~~six ~~during~~month period compared to $3.07 for the same period a year ago.

The ~~Partnership~~increase ~~expects to experience continued declines~~ in ~~both~~ natural gas ~~and~~revenues ~~oil~~of ~~production~~55% ~~volumes~~contrasts ~~over~~to the ~~wells’~~more ~~life~~significant ~~cycles~~increase ~~until~~in ~~such~~oil ~~time~~revenues ~~that~~of ~~the~~73%. The Partnership’s ~~Wattenberg~~oil ~~wells~~revenue ~~may~~increase bewas ~~successfully~~bolstered ~~recompleted. Subsequent~~by toincreased aoil ~~successful~~production ~~recompletion~~volumes, ~~production~~per ~~will~~Bbl ~~once~~of ~~again~~7% beas ~~expected~~compared to the decline in natural gas production volumes, per Mcf of 7% during the current six month period.

Three months ended June 30, 2010 as compared to three months ended June 30, 2009

The $0.2 million, or 35% increase in total sales for the 2010 second quarter as compared to the prior year second quarter was primarily a reflection of the higher average sales price per Mcfe of 51%, which was partially offset by production volume decrease of 11%. Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $4.34 for the current year quarter compared to $2.87 for the same quarter a year ago.

The Partnership expects to experience declines in both natural gas and oil production volumes over the wells’ life cycles until such time that the Partnership’s Wattenberg wells may be successfully recompleted. Subsequent to a successful recompletion, production will once again be expected to decline.

Natural Gas and Oil Pricing

Financial results depend upon many factors, particularly the price of natural gas and oil and ~~the~~on ~~Partnership~~PDC’s ability to market ~~its~~the Partnership’s production effectively. Natural gas and oil prices are among the most volatile of all commodity prices. ~~These~~This price ~~variations~~volatility ~~have~~has a material impact on the Partnership’s financial results. Natural gas and oil prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality and availability of sufficient pipeline capacity. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply ~~situation~~situations from time to time. Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities and transportation capacity beyond the Partnership’s control. Oil pricing, unlike natural gas pricing, is driven predominantly by global supply and demand relationships.

The price ~~the~~at ~~Partnership~~which ~~receives~~PDC ~~for~~markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby ~~region~~regional prices. The CIG Index, and other indices for production delivered to Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in ~~recent months and for two out of~~ the last ~~six~~year ~~months~~and ~~became a slight positive differential, which~~ is ~~inconsistent~~lower ~~with~~than historical variances. This negative differential between NYMEX and CIG averaged $1.6213 and $1.38 for the three and six months ended ~~March~~June 3130, 2009, respectively, and narrowed to an average of $0.1648 and $0.32 for the three and six months ended ~~March~~June 3130, 2010, respectively.

- 1317 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The Managing General Partner ~~uses~~is authorized to utilize natural gas and oil derivative instruments to manage price risk for PDC as well as sponsored drilling partnerships. Commodity price risk management, net includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil production. The Managing General Partner sets these instruments for PDC, and the various partnerships managed by PDC. Derivative financial instrument positions taken by the Managing General Partner on the Partnership’s behalf, are specifically designated to the Partnership’s production volumes. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, to the Partnership’s unaudited condensed financial statements included in this report, for additional details on the Partnership’s derivative financial instruments.

The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain (loss), net.

	Three months ended March 31,
	Three months ended June 30,						Six months ended June 30,
Commodity price risk management, net	2010			2009
Commodity price risk management gain (loss), net	2010			2009			2010			2009
Realized gains
Oil	$	3032,~~655~~782		$	~~116~~76,~~448~~725		$	63,437		$	193,173
Natural Gas		~~296~~17,~~165~~148			~~483~~322,~~666~~665			313,313			806,331
Total realized gain, net		~~326~~49,~~820~~930			~~600~~399,~~114~~390			376,750			999,504
Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized		(302,726	)		(495,526	)
Reclassification of realized gains included in prior periods unrealized		(45,542	)		(429,310	)		(196,747	)		(796,234	)
Unrealized gain (loss) for the period		~~884~~231,~~016~~159			(~~166~~516,~~623~~857	)		963,654			(812,082	)
Total unrealized gain (loss), net		~~581~~185,~~290~~617			(~~662~~946,~~149~~167	)		766,907			(1,608,316	)
Commodity price risk management gain (loss), net	$	~~908~~235,~~110~~547		$	(62546,~~035~~777	)	$	1,143,657		$	(608,812	)

~~Realized~~Six ~~gains~~months ~~recognized~~ended inJune ~~the~~30, ~~first quarter of~~ 2010 ~~which~~as ~~total $0.3 million, are a result of lower natural gas and oil spot prices at the settlement date~~ compared to ~~the~~six ~~respective~~months ~~strike~~ended ~~price. During~~June ~~the first quarter of 2010~~30, the Partnership recorded unrealized derivative gains of $0.9 million, $1.1 million of which was related to the Partnership’s natural gas positions, offset in part by unrealized losses on the Partnership’s CIG basis swaps of $0.2 million, as the forward basis differential between NYMEX and CIG has continued to narrow.2009

~~During~~The realized derivative gains for the ~~first~~2010 ~~quarter~~six ofmonth ~~2009,~~period ~~the~~were ~~Partnership~~$0.4 ~~experienced~~million. These realized gains ~~and~~were ~~unrealized~~primarily ~~derivative~~a ~~losses~~result asof lower natural gas and oil spot prices ~~declined. The~~at ~~net~~settlement ~~unrealized~~compared ~~loss~~to ~~for~~the respective strike price, offset in part by realized losses due to the ~~first~~basis ~~quarter~~differential ofbetween ~~2009~~NYMEX and CIG being narrower than the strike price of $0the derivative position.2 For ~~million~~the ~~was~~six ~~comprised~~month ofperiod, arealized ~~decrease~~gains inrelated ~~fair~~to ~~value~~natural ofgas and oil derivatives were $0.5 million and realized losses on the Partnership’s CIG basis swaps ofwere $0.61 million. Unrealized ~~which~~gains ~~resulted~~on ~~from~~the aPartnership’s ~~steeper~~natural ~~decline~~gas inand ~~NYMEX~~oil ~~pricing~~positions ~~relative~~for tothe ~~CIG~~six ~~pricing~~months ~~that~~period ~~was~~were ~~partially offset by a~~ $0.49 million ~~net~~due ~~unrealized~~primarily ~~gain~~to ~~from~~a downward shift in the ~~Partnership’s~~natural ~~commodity~~gas ~~derivatives~~and oil forward curves.

~~Realized~~For ~~derivative~~the ~~gains,~~2009 ~~down~~six ~~46%~~month ~~from~~period, the ~~prior~~Partnership ~~year~~realized ~~first~~significant ~~quarter,~~derivative gains ~~contributed~~as ana ~~additional~~result ~~$2.34~~of ~~per~~lower ~~Mcfe~~natural gas and oil prices at settlement compared to ~~this~~the ~~year’s~~respective ~~total~~derivative ~~revenues~~strike prices. ~~Comparatively,~~Unrealized losses for the ~~total~~period ~~per~~were ~~Mcfe~~primarily ~~price~~related ~~realized,~~to ~~consisting~~oil ofswaps, as the ~~average~~forward ~~sales~~strip price of oil rebounded during the period, and ~~realized~~the ~~derivative~~CIG ~~gains~~basis swaps, ~~increased~~as 9%the toforward ~~$8.37~~basis ~~for~~differential during the ~~current~~period ~~year~~between ~~quarter~~NYMEX ~~from~~and ~~$7.68~~CIG ~~for~~continued to narrow from the ~~prior~~strike ~~year~~price ~~first~~of ~~quarter~~the derivative position.

~~Natural~~Three ~~Gas~~months ~~and~~ended ~~Oil~~June Sales Derivative Instruments. The Managing General Partner uses various derivative instruments to manage fluctuations in natural gas and oil prices. The Partnership has in place a series of collars30, ~~fixed~~2010 ~~price swaps and basis protection swaps on a portion of the Partnership’s natural gas and oil production~~ as ~~set~~compared forth in the following table. Under the Partnership’s collar arrangements, if the applicable index rises above the ceiling price, the Managing General Partner pays the counterparty; however, if the index drops below the floor price, the counterparty pays the Managing General Partner. Under the Partnership’s commodity swap arrangements, if the applicable index rises above the swap price, the Managing General Partner pays the counterparty; however, if the index drops below the swap price, the counterparty pays the Managing General Partner. Under the Partnership’s basis protection swaps, if the differential widens beyond the basis swap price, then the counterparty pays the Managing General Partner; however, if the differential narrows, then the Managing General Partner pays the counterparty. Because the Partnership sells all of its physical natural gas and oil at similar prices to ~~the~~three ~~indexes~~months ~~inherent~~ended inJune ~~the Partnership’s derivative instruments~~30, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership’s commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps. 2009

-The 14realized derivative gains for the 2010 second quarter were approximately $50,000. These realized gains are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the quarter, realized gains related to natural gas and oil derivatives were $0.2 million and realized losses on the Partnership’s CIG basis swaps were $0.1 million. For the 2010 second quarter, the unrealized gains were primarily related to the oil positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential. Unrealized gains on the Partnership’s oil positions and CIG basis swaps for the 2010 second quarter were $0.1 million and $0.1 million, respectively.

- 18 -

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~The~~For ~~following~~the ~~table~~2009 ~~presents~~second quarter, the Partnership’s realized significant derivative gains ~~positions~~as ina ~~effect~~result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices. Unrealized losses for the period were primarily related to oil swaps, as the forward strip price of ~~March~~oil 31rebounded during the period, ~~2010~~and the CIG basis swaps, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
			Weighted Average Contract Price
Commodity/Index	Quantity (Gas-Mmbtu)		Floors		Ceilings		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at March 31, 2010(1)
Natural Gas
CIG
10/01 - 12/31/2010		26,198	$	4.75	$	9.45		-	$	-		-	$	-		$	17,010
01/01 - 03/31/2011		39,297		4.75		9.45		-		-		-		-			18,644
NYMEX
04/01 - 06/30/2010		-		-		-		98,622		5.55		90,872		(1.88	)		26,612
07/01 - 09/30/2010		-		-		-		97,526		5.56		89,756		(1.88	)		1,260
10/01 - 12/31/2010		11,261		5.75		8.30		53,424		6.05		61,967		(1.88	)		644
01/01 - 03/31/2011		15,307		5.75		8.30		28,029		6.81		43,336		(1.88	)		(11,662	)
04/01 - 12/31/2011		-		-		-		245,524		6.77		245,524		(1.88	)		(4,289	)
2012-2013		20,604		6.00		8.27		568,755		7.05		589,370		(1.88	)		(174,104	)
Total Natural Gas		112,667						1,091,880				1,120,825					(125,885	)
Oil
NYMEX
04/01 - 06/30/2010		-		-		-		2,190		92.96		-		-			18,930
07/01 - 09/30/2010		-		-		-		2,214		92.96		-		-			17,378
10/01 - 12/31/2010		-		-		-		2,214		92.96		-		-			16,340
01/01 - 03/31/2011		-		-		-		893		70.75		-		-			(12,794	)
04/01 - 12/31/2011		-		-		-		2,789		70.75		-		-			(40,909	)
Total Oil		-						10,300				-					(1,055	)
Total Natural Gas and Oil																$	(126,940	)

Natural Gas and Oil Sales Derivative Instruments. The Managing General Partner on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices. The Partnership has in place a series of collars, fixed-price swaps and basis swaps on a portion of the Partnership’s natural gas and oil production. See Note 5, Derivative Financial Instruments to the Partnership’s financial statements included in the 2009 Form 10-K for an additional discussion on how each derivative type impacts the Partnership’s cash flows.

~~(1)~~The ~~Approximately~~following 9%table ofpresents the ~~fair value of the~~ Partnership’s derivative ~~assets~~positions ~~and~~in ~~all~~effect as of ~~the~~June ~~Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3)~~30, ~~see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report~~2010.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-Mmbtu)		Weighted Average Contract Price				Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at June 30, 2010(1)
Commodity/ Index	Quantity (Gas-Mmbtu)		Floors		Ceilings		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at June 30, 2010(1)

Natural Gas
CIG
10/01 - 12/31/2010		26,198	$	4.75	$	9.45		-	$	-		-	$	-		$	15,990
01/01 - 03/31/2011		39,297		4.75		9.45		-		-		-		-			19,582

NYMEX
07/01 - 09/30/2010		-		-		-		97,526		5.56		89,756		(1.88	)		(16,704	)
10/01 - 12/31/2010		11,261		5.75		8.30		53,424		6.05		61,967		(1.88	)		(998	)
01/01 - 03/31/2011		15,307		5.75		8.30		28,029		6.81		43,336		(1.88	)		(6,922	)
04/01 - 06/30/2011		-		-		-		82,998		6.78		82,998		(1.88	)		29,556
07/01 - 12/31/2011		-		-		-		162,526		6.76		162,526		(1.88	)		2,625
2012-2013		20,604		6.00		8.27		568,755		7.05		589,370		(1.88	)		(24,314	)
Total Natural Gas		112,667						993,258				1,029,953					18,815

Oil
NYMEX
07/01 - 09/30/2010		-		-		-		2,214		92.96		-		-			36,614
10/01 - 12/31/2010		-		-		-		2,214		92.96		-		-			33,659
01/01 - 03/31/2011		-		-		-		893		70.75		-		-			(6,557	)
04/01 - 06/30/2011		-		-		-		912		70.75		-		-			(7,429	)
07/01 - 12/31/2011		-		-		-		1,877		70.75		-		-			(16,425	)
Total Oil		-						8,110				-					39,862

Total Natural Gas and Oil																$	58,677

(1) Approximately 11% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.

Natural Gas and Oil Production Costs

Generally, natural gas and oil production costs vary with changes in total natural gas and oil sales and production volumes. ~~Property~~Production ~~and severance~~ taxes are estimates by the Managing General Partner based on tax rates determined using ~~historical~~published information. These ~~amounts~~estimates are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. ~~Property~~Production ~~and severance~~ taxes vary directly with total natural gas and oil sales. Transportation costs vary directly with production volumes. Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve. In addition, general oil field services and all other costs vary and can fluctuate based on services required. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal, environmental remediation and service rig workovers.

~~For the three months ended March 31, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency~~-~~basis,~~ ~~remained~~19 ~~substantially unchanged at approximately 140,000 Mcfe. Production and operating costs remained substantially unchanged, as well, at approximately $155,000 quarter~~-to-quarter. Although higher commodity valuations increased production taxes during the three months ended March 31, 2010, this increase was partially offset by a downward adjustment to these accrued taxes due to revisions to tax rates by the Colorado tax agencies, of which the Partnership was notified during the first quarter 2010. Production and operating costs per Mcfe were $1.09 for the three months ended March 31, 2010 compared to $1.16 for the comparable period in 2009.

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Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

For the six months ended June 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 5%, which reflects overall, the normally-occurring production declines throughout a natural gas and oil well’s production life cycles. Production and operating costs were higher by approximately $0.3 million, or 91%, primarily due to accruing environmental remediation costs in 2010 and higher 2010 well operations costs as a result of the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement. Production and operating costs per Mcfe were $2.39 for the six months ended June 30 of 2010 compared to $1.19 for the comparable period in 2009.

Three months ended June 30, 2010 as compared to three months ended June 30, 2009

For the quarter ended June 30, 2010 compared to the same period in 2009, natural gas and oil production on an energy equivalency-basis, decreased 11%, primarily as a result of reduced performance by the Partnership’s Grand Valley wells due to higher fluid production as well as expected normally-occurring production life-cycle decline in both operating fields. Natural gas and oil production costs increased approximately $0.3 million, or 168%, primarily due to accruing environmental remediation costs in the quarter, production tax increases on higher commodity valuations and higher Grand Valley lease operating costs due to higher fluid hauling expenditures and well workover costs. Production and operating costs per Mcfe were $3.65 and $1.22 for the quarter ended June 30, 2010 and 2009, respectively.

Direct Costs−General and Administrative

~~Direct~~Six costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation independent engineer’s reserve reports and legal matters. Direct costs decreased during the three months ended ~~March~~June 3130, 2010, as compared to ~~the~~six ~~same~~months ~~period~~ended inJune ~~2009~~30, ~~by approximately $33,000 principally due to billings for professional services.~~2009

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs decreased during the six months ended June 30, 2010, compared to the same period in 2009, by approximately $0.1 million principally due to reduced billings for professional services.

Three months ended June 30, 2010 as compared to three months ended June 30, 2009

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs decreased during the three months ended June 30, 2010, compared to the same period in 2009, by approximately $0.1 million principally due to reduced billings for professional services.

Depreciation, Depletion and Amortization

DD&A expense related to natural gas and oil properties is directly related to production volumes for the period. For the quarter ended ~~March~~June 3130, 2009, the Partnership’s natural gas and oil economically producible reserve quantities were determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2008. Upon adoption, in the fourth quarter of 2009, of the SEC’s final rule regarding the modernization of oil and gas reporting ~~in the fourth quarter of 2009~~, the Partnership changed to a valuation price determined by the 12-month average of the first-day-of-the-month price during each month of 2009.

~~The~~- ~~DD&A~~20 expense rate per Mcfe increased to $3.64 for the 2010 three month period, compared to $3.39 during the same period in 2009 as calculated by the respective methodologies described above. The variance in the per Mcfe rates for the 2010 period compared to the 2009 period is primarily the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates, in addition to lower proved developed reserves at December 31, 2009 compared to December 31, 2008.-

Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

The DD&A expense rate per Mcfe increased to $3.69 for the 2010 six month period, compared to $3.27 during the same period in 2009, as calculated by the respective methodologies described above. The increase in the per Mcfe rates for the 2010 period compared to the 2009 period is primarily the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates, in addition to higher DD&A rates due to the effects of lower proved developed producing reserves at December 31, 2009 compared to December 31, 2008. These increased rates, which partially offset the effect of somewhat lower production volumes, resulted in the DD&A expense increase of approximately $0.1 million for the 2010 six month period compared to the same 2009 period.

Three months ended June 30, 2010 as compared to three months ended June 30, 2009

The DD&A expense rate per Mcfe increased to $3.74 for the 2010 second quarter, compared to $3.18 during the same quarter in 2009 as calculated by the respective methodologies described above. The variance in the per Mcfe rates for the 2010 second quarter compared to the 2009 second quarter is a result of the combined effects of the changing production mix between fields and lower proved developed producing reserves noted above. These increased rates, which were partially offset by an 11% decline in production volumes, resulted in the DD&A expense increase of approximately $27,000 for the 2010 second quarter compared to the same 2009 quarter.

Capital Resources and Liquidity

The Partnership’s primary sources of cash ~~are~~for both the three and the six months ended June 30, 2010 were from funds ~~generated~~provided ~~from~~by operating activities which include the sale of natural gas and oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating ~~cost~~costs, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership ~~manages~~attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold economic hedges for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of ~~March~~June 3130, 2010, the Partnership had natural gas and oil derivative positions in place covering 8178% of expected natural gas production and 79% of expected oil production for the remainder of 2010, at an average price of $34.9008 per Mcf and $92.96 per Bbl, respectively. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas and oil production activities and commodity gains (losses). Natural gas and oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining ~~life~~lives of the wells. Therefore, the Partnership ~~expects~~anticipates a lower annual level of natural gas and oil production and, in the absence of significant price increases or recompletions, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners through the remainder of 2010 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the Well Recompletion Plan activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Well Recompletion Plan. Future cash distributions, in the event that the proposed Merger Agreement is not completed, may also be reduced to fund ~~well~~the ~~recompletions~~Wattenberg inField ~~the~~ Codell formation ofwell ~~the Wattenberg field~~recompletions.

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Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

Working capital at ~~March~~June 3130, 2010 was $0.83 million compared to working capital of $0.67 million at December 31, 2009. This ~~increase~~decrease of $0.24 million was primarily due to the following changes in accounts receivable or payable balances:

· Natural gas and oil receivables ~~remained~~decreased ~~unchanged~~to ~~at approximately~~ $0.54 million as of ~~March~~June 3130, 2010, ~~and~~from $0.5 million as of December 31, 2009~~, respectively~~.

· Realized derivative gains receivables decreased toby $0.23 million as of ~~March~~June 3130, 2010~~, from $0~~.~~3 million as of December 31, 2009.~~

· Net short-term unrealized derivative gains receivable increased to $0.1 million as of ~~March~~June 3130, 2010.

· ~~Due~~Accounts topayable ~~Managing General Partner-other, net, excluding natural gas~~ and ~~oil~~accrued ~~sales~~expenses ~~received~~increased ~~from~~by ~~third parties and realized derivative gains, decreased to a~~ $0.23 million ~~liability~~ as of ~~March~~June 3130, 2010, ~~from~~due ato ~~$0.3~~the ~~million~~environmental ~~liability~~remediation ~~as of December 31, 2009~~accrual.

Decrease in Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, to a $0.1 million liability as of June 30, 2010, from a $0.3 million liability as of December 31, 2009, due to Partnership pay down to Managing General Partner.

Cash Flows

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and oil or environmental protection. These amounts totaled approximately $56,000 and $110,~~200~~000 for the ~~three~~six months ended ~~March~~June 3130, 2010 and 2009, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in November 2004 and has distributed $3334.52 million through ~~March~~June 3130, 2010. The table below presents the cash distributions to the Managing General Partner and Investor Partners, including Managing General Partner distributions relating to limited partnership units repurchased, for the periods described.

Quarter ended March 31,	Managing General Partner Distributions			Investor Partners Distributions		Total Distributions
Three months	Managing		Investor
2010	$	177,150		$	708,601	$	885,751
ended	General Partner		Partners	Total
2009	$	160,013		$	640,053	$	800,066
June 30,	Distributions		Distributions	Distributions
2010	$ 130,011		$ 520,046	$ 650,057
2009	$ 177,731		$ 710,926	$ 888,657
Six months	Managing		Investor
ended	General Partner		Partners	Total
June 30,	Distributions		Distributions	Distributions
2010	$ 307,161		$ 1,228,647	$ 1,535,808
2009	$ 337,744		$ 1,350,979	$ 1,688,723

~~Cash~~- ~~Flows~~22 ~~From Operating Activities~~-

Net cash provided by operating activities was $0.9 million for the three months ended March 31, 2010, compared to $0.8 million for the comparable period in 2009. The $0.1 million increase in cash provided by operating activities was due primarily to the following:

· An increase in natural gas and oil sales receipts of $0.2 million, or 28%, accompanied by a slight decrease in direct costs – general and administrative; and

· A decrease in commodity price risk management realized gains receipts of $0.1 million.

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Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Cash Flows From Operating Activities

Net cash provided by operating activities was $1.5 million for the six months ended June 30, 2010, compared to $1.7 million for the comparable period in 2009. The approximately $0.2 million decrease in cash provided by operating activities was due primarily to the following:

An increase in natural gas and oil sales receipts of $0.4 million, or 40%, accompanied by a decrease in direct costs – general and administrative of $0.1 million, or 67%;

A decrease in commodity price risk management realized gains receipts of $0.5 million or 43% and an increase in natural gas and oil production costs of approximately $0.3 million, or 91%.

Commitments and Contingencies

See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements, included in this report.

Recent Accounting Standards

See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements, included in this report.

Critical Accounting Policies and Estimates

The preparation of the accompanying unaudited condensed financial statements in conformity with U.S. GAAP requires management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.

There have been no other significant changes to the Partnership’s critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership’s 2009 Form 10-K, such policies include revenue recognition, derivatives instruments, fair value measurements, natural gas and oil properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties.

Off-Balance 18Sheet -Arrangements

Currently, the Partnership does not have any off-balance sheet arrangements.

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Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4T. Controls and Procedures

The Partnership has no direct management or officers. The management, officers and other employees that provide services on behalf of the Partnership are employed by the Managing General Partner.

(a) Evaluation of Disclosure Controls and Procedures

As of ~~March~~June 3130, 2010, PDC, as Managing General Partner of the Partnership, carried out an evaluation under the supervision and with the participation of the Managing General Partner’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’s Disclosure Committee in an effort to ensure that information required to be disclosed in the SEC reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required financial disclosure.

Based on the results of this evaluation, the Managing General Partner’s Chief Executive Officer and the Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of ~~March~~June 3130, 2010.

(b) Changes in Internal Control over Financial Reporting

PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended ~~March~~June 3130, 2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

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Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

Information regarding the Registrant’s legal proceedings can be found in Note 6, Commitments and Contingencies, to the Partnership’s accompanying unaudited condensed financial statements.

Item 1A.

Risk Factors

Not applicable.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Unit Repurchase Program: Beginning November 2007, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit, during any calendar year, for all requesting Investor Partner unit repurchases of 10% of the initial subscription units. As of July 1, 2010, the Managing General Partner suspended the opportunity for an individual investor partner to request that PDC repurchase their respective limited partnership units under the terms of the program, pending the outcome of the proposed Merger Agreement.

The following table presents information about the Managing General Partner’s limited partner unit repurchases during the three months ended ~~March~~June 3130, 2010.

Period	Total Number of Units Repurchased		Average Price Paid per Unit
			Average Price
January 1−31, 2010		-	$	-
	Total Number of		Paid per
February 1−28, 2010		0.50		5,320
Period	Units Repurchased		Unit
March 1−31, 2010		-		-
April 1−30, 2010		0.50	$	4,650
Total first quarter Unit Repurchase Program repurchases		0.50
May 1−31, 2010		-		-
June 1−30, 2010		0.50		4,420
Total second quarter Unit Repurchase Program repurchases		1.00

Item 3.

Defaults Upon Senior Securities

Not applicable.

Item 4.

[Removed and Reserved]

Item 5.

Other Information

Not applicable.

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Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.

Exhibits

(a)	Exhibit Index.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

3.1

Limited Partnership Agreement

10-K

000-51218

3.1

08/04/2009

2.1

Agreement and Plan of Merger by and among PDC, DP 2004 Merger Sub, LLC and PDC 2004-A Limited Partnership

8-K

000-51218

2.1

06/09/2010

3.1

Limited Partnership Agreement

PREM14A

000-51218

Annex F

07/08/2010

3.2

Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law

10-K

000-51218

3.2

08/04/2009

10.1

Drilling and operating agreement between the Partnership and PDC, as Managing General Partner of the Partnership

10-K

000-51218

10.1

08/04/2009

31.1

Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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 Partnership.

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Index

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 2004-A Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By: /s/ Richard W. McCullough Richard W. McCullough Chairman and Chief Executive Officer August 12, 2010

Richard W. McCullough

Chairman and Chief Executive Officer

May 14, 2010

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	~~Date~~
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	August 12, 2010	~~May 14, 2010~~
Richard W. McCullough	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	August 12, 2010	~~May 14, 2010~~
Gysle R. Shellum	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	August 12, 2010	~~May 14, 2010~~
R. Scott Meyers	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal accounting officer)

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Filing Compare · PDC 2004-A Limited Partnership