UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

x 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 000-51309

PDC 2005-A Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	20-2088726
(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 þ No 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 o¨ Non-accelerated filer o¨ Smaller reporting company þ

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

As of ~~March~~June 3130, 2010 the Partnership had 1,996.87 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page	~~Page~~
	PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	2	2
	Condensed Statements of Operations (unaudited)	3	3
	Condensed Statements of Cash Flows (unaudited)	4	4
	Notes to Unaudited Condensed Financial Statements	5	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21	19
Item 4T.	Controls and Procedures	21	19
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	22	20
Item 1A.	Risk Factors	22	20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22	20
Item 3.	Defaults Upon Senior Securities	22	20
Item 4.	[Removed and Reserved]	22	20
Item 5.	Other Information	22	20
Item 6.	Exhibits	23	21
	SIGNATURES	24	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 2005-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 are not the exclusive means of identifying forward-looking statements herein. 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:

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. PDC now conducts business under the name “PDC Energy.”

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 rig services, 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 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 31, 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.

- 1 -

Index

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements (unaudited)

PDC 2005-A Limited Partnership
Condensed Balance Sheets
(unaudited)
	March 31, 2010			December 31, 2009*
Assets
Current assets:
Cash and cash equivalents	$	224,751		$	224,751
Accounts receivable		449,001			408,544
Oil inventory		24,599			33,305
Due from Managing General Partner-derivatives		724,310			554,898
Due from Managing General Partner-other, net		489,922			355,801
Total current assets		1,912,583			1,577,299
Oil and gas properties, successful efforts method, at cost		44,424,848			44,419,132
Less: Accumulated depreciation, depletion and amortization		(21,528,283	)		(20,809,309	)
Oil and gas properties, net		22,896,565			23,609,823
Due from Managing General Partner-derivatives		1,290,847			516,653
Other assets		31,131			24,607
Total noncurrent assets		24,218,543			24,151,083
Total Assets	$	26,131,126		$	25,728,382
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	46,400		$	41,448
Due to Managing General Partner-derivatives		611,841			529,551
Total current liabilities		658,241			570,999
Due to Managing General Partner-derivatives		1,593,141			1,487,222
Asset retirement obligations		519,533			512,800
Total liabilities		2,770,915			2,571,021
Commitments and contingent liabilities
Partners' equity:
Managing General Partner		4,687,026			4,646,456
Limited Partners - 1,996.87 units issued and outstanding		18,673,185			18,510,905
Total Partners' equity		23,360,211			23,157,361
Total Liabilities and Partners' Equity	$	26,131,126		$	25,728,382

PDC 2005-A Limited Partnership

Condensed Balance Sheets

(unaudited)

	June 30,			December 31,
	2010				2009*
Assets

Current assets:
Cash and cash equivalents	$	224,751		$	224,751
Accounts receivable		317,051			408,544
Oil inventory		20,350			33,305
Due from Managing General Partner-derivatives		625,669			554,898
Due from Managing General Partner-other, net		161,857			355,801
Total current assets		1,349,678			1,577,299


Oil and gas properties, successful efforts method, at cost		44,432,476			44,419,132
Less: Accumulated depreciation, depletion and amortization		(22,240,541	)		(20,809,309	)
Oil and gas properties, net		22,191,935			23,609,823

Due from Managing General Partner-derivatives		1,219,969			516,653
Other assets		37,804			24,607
Total noncurrent assets		23,449,708			24,151,083

Total Assets	$	24,799,386		$	25,728,382

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	34,687		$	41,448
Due to Managing General Partner-derivatives		493,908			529,551
Total current liabilities		528,595			570,999

Due to Managing General Partner-derivatives		1,275,281			1,487,222
Asset retirement obligations		526,366			512,800
Total liabilities		2,330,242			2,571,021

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		4,508,813			4,646,456
Limited Partners - 1,996.87 units issued and outstanding		17,960,331			18,510,905
Total Partners' equity		22,469,144			23,157,361

Total Liabilities and Partners' Equity	$	24,799,386		$	25,728,382

__________________________________

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2005-A Limited Partnership
Condensed Statements of Operations
(unaudited)
	Three months ended March 31,
	2010		2009
Revenues:
Natural gas and oil sales	$	1,286,676	$	863,692
Commodity price risk management gain (loss), net		1,221,452		(40,244	)
Total revenues		2,508,128		823,448
Operating costs and expenses:
Natural gas and oil production costs		266,591		318,164
Direct costs - general and administrative		35,226		151,967
Depreciation, depletion and amortization		718,974		1,082,145
Accretion of asset retirement obligations		6,733		4,624
Total operating costs and expenses		1,027,524		1,556,900
Income (loss) from operations		1,480,604		(733,452	)
Interest income		-		11,700
Net income (loss)	$	1,480,604	$	(721,752	)
Net income (loss) allocated to partners	$	1,480,604	$	(721,752	)
Less: Managing General Partner interest in net income (loss)		296,121		(144,350	)
Net income (loss) allocated to Investor Partners	$	1,184,483	$	(577,402	)
Net income (loss) per Investor Partner unit	$	593	$	(289	)
Investor Partner units outstanding		1,996.87		1,996.87

PDC 2005-A Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended June 30,					Six months ended June 30,
	2010		2009			2010		2009
Revenues:
Natural gas and oil sales	$	926,848	$	631,896		$	2,213,524	$	1,495,588
Commodity price risk management gain (loss), net		331,609		(780,538	)		1,553,061		(820,782	)
Total revenues		1,258,457		(148,642	)		3,766,585		674,806

Operating costs and expenses:
Natural gas and oil production costs		334,922		409,071			601,513		727,235
Direct costs - general and administrative		43,585		116,902			78,811		268,869
Depreciation, depletion and amortization		712,258		858,715			1,431,232		1,940,860
Accretion of asset retirement obligations		6,833		4,624			13,566		9,248
Total operating costs and expenses		1,097,598		1,389,312			2,125,122		2,946,212

Income (loss) from operations		160,859		(1,537,954	)		1,641,463		(2,271,406	)

Interest income		-		10,267			-		21,967

Net income (loss)	$	160,859	$	(1,527,687	)	$	1,641,463	$	(2,249,439	)

Net income (loss) allocated to partners	$	160,859	$	(1,527,687	)	$	1,641,463	$	(2,249,439	)
Less: Managing General Partner interest in net income (loss)		32,172		(305,538	)		328,293		(449,888	)
Net income (loss) allocated to Investor Partners	$	128,687	$	(1,222,149	)	$	1,313,170	$	(1,799,551	)

Net income (loss) per Investor Partner unit	$	64	$	(612	)	$	658	$	(901	)

Investor Partner units outstanding		1,996.87		1,996.87			1,996.87		1,996.87

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2005-A Limited Partnership
Condensed Statements of Cash Flows
(unaudited)
	Three months ended March 31,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	1,480,604		$	(721,752	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		718,974			1,082,145
Accretion of asset retirement obligations		6,733			4,624
Unrealized (gain) loss on derivative transactions		(755,397	)		934,841
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(40,457	)		70,086
Decrease in oil inventory		8,706			1,494
Increase in other assets		(6,524	)		-
Increase (decrease) in accounts payable and accrued expenses		4,952			(8,212	)
Increase in due from Managing General Partner - other, net		(134,121	)		(397,320	)
Net cash provided by operating activities		1,283,470			965,906
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(5,716	)		(16,279	)
Net cash used in investing activities		(5,716	)		(16,279	)
Cash flows from financing activities:
Distributions to Partners		(1,277,754	)		(947,770	)
Net cash used in financing activities		(1,277,754	)		(947,770	)
Net increase in cash and cash equivalents		-			1,857
Cash and cash equivalents, beginning of period		224,751			314,610
Cash and cash equivalents, end of period	$	224,751		$	316,467

PDC 2005-A Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Six months ended June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	1,641,463		$	(2,249,439	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		1,431,232			1,940,860
Accretion of asset retirement obligations		13,566			9,248
Unrealized (gain) loss on derivative transactions		(1,021,671	)		2,300,112
Changes in operating assets and liabilities:
Decrease in accounts receivable		91,493			75,031
Decrease in oil inventory		12,955			5,852
Increase in other assets		(13,197	)		(13,834	)
Decrease in accounts payable and accrued expenses		(6,761	)		(31,533	)
Decrease in due from Managing General Partner - other, net		193,944			589,846
Net cash provided by operating activities		2,343,024			2,626,143

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(13,344	)		(18,098	)
Proceeds from drilling advance refund from Managing General Partner		-			108,531
Net cash (used in) provided by investing activities		(13,344	)		90,433

Cash flows from financing activities:
Distributions to Partners		(2,329,680	)		(2,606,502	)
Net cash used in financing activities		(2,329,680	)		(2,606,502	)

Net increase in cash and cash equivalents		-			110,074
Cash and cash equivalents, beginning of period		224,751			314,610
Cash and cash equivalents, end of period	$	224,751		$	424,684

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2005-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2005-A Limited Partnership was organized as a limited partnership on November 30, 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 properties. Upon completion of the sale of Partnership units on February 9, 2005, 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 124.79 units of limited partner interests and 1,872.08 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,~~501~~502 Investor Partners. As of ~~March~~June 3130, 2010, the Managing General Partner has repurchased 2324.750 units of the total 1,996.87 outstanding units of Partnership interests from Investor Partners at an average price of $9,~~944~~891 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.

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 ~~presentation~~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 three and six months ended ~~March~~June 3130, 2010, and the cash flows for the ~~same~~six ~~period~~months ended June 30, 2010, are not necessarily indicative of the results to be expected for the full year or any other future period.

~~The~~Note ~~accompanying~~2−Recent ~~interim~~Accounting unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership's Form 10-K for the year ended December 31, 2009, as filed with the SEC on March 31, 2010 (“the 2009 Form 10-K”).Standards

~~The~~Recently ~~Managing~~Issued ~~General~~Accounting 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.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.

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Index

PDC 2005-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

~~Note~~Internal ~~2−Recent~~Control ~~Accounting~~over ~~Standards~~Financial Reporting in Exchange Act Periodic Reports

~~Recently~~On ~~Adopted~~July ~~Accounting~~21, ~~Standards~~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.

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

Note 3−Transactions with Managing General Partner and Affiliates

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	$	377,578		$	392,255
	2010			2009
Commodity price risk management, realized gains		328,340			396,498
Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	298,199		$	392,255
Other (1)		(215,996	)		(432,952	)
Commodity Price Risk Management, Realized Gains		49,073			396,498
Total Due from Managing General Partner-other, net	$	489,922		$	355,801
Other (1)		(185,415	)		(432,952	)
Total Due from Managing General Partner-other, net	$	161,857		$	355,801

(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.

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Index

PDC 2005-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

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 ~~March~~June 3130, 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.

	Three months ended March 31,
	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
Well operations and maintenance	$	~~175~~233,~~462~~661	$	~~213~~333,~~035~~886	$	409,123	$	546,921
Gathering, compression and processing fees		4547,~~244~~186		4647,~~734~~749		92,430		94,483
Direct costs - general and administrative		3543,~~226~~585		~~151~~116,~~967~~902		78,811		268,869
Cash distributions*		~~267~~220,~~709~~425		~~195~~346,~~042~~958		488,134		542,001

*Cash distributions include $1210,~~158~~040 and $22,198 during the three and six months ended ~~March~~June 3130, 2010, respectively, and $515,~~489~~213 and $20,702 during the three and six months ended ~~March~~June 3130, 2009, respectively, 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.~~

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 ~~March~~June 3130, 2010, the impact of ~~non-performance~~nonperformance risk on the fair value of the ~~Managing General Partner~~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.

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Index

PDC 2005-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 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	$	520,527		$	551,024		$	1,071,551
Total assets		520,527			551,024			1,071,551
Liabilities:
Commodity based derivatives		(41,267	)		(90,592	)		(131,859	)
Basis protection derivative contracts		-			(1,884,914	)		(1,884,914	)
Total liabilities		(41,267	)		(1,975,506	)		(2,016,773	)
Net asset (liability)	$	479,260		$	(1,424,482	)	$	(945,222	)
As of March 31, 2010
As of June 30, 2010
Assets:
Commodity based derivatives	$	1,~~833~~637,~~261~~940		$	~~181~~207,~~896~~698		$	21,~~015~~845,~~157~~638
Total assets		1,~~833~~637,~~261~~940			~~181~~207,~~896~~698			21,~~015~~845,~~157~~638
Liabilities:
Commodity based derivatives		-			(8649,~~748~~075	)		(8649,~~748~~075	)
Basis protection derivative contracts		-			(21,~~118~~720,~~234~~114	)		(21,~~118~~720,~~234~~114	)
Total liabilities		-			(21,~~204~~769,~~982~~189	)		(21,~~204~~769,~~982~~189	)
Net asset (liability)	$	1,~~833~~637,~~261~~940		$	(21,~~023~~561,~~086~~491	)	$	~~(189~~76,~~825~~449	)

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	$	(1,424,482	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		~~(132~~200,~~549~~266	)
Settlements		(~~466~~337,~~055~~275	)
Fair value, net liability, as of March 31, 2010	$	(2,023,086	)
Fair value, net liability, as of June 30, 2010	$	(1,561,491	)
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	$	~~(166~~148,~~976~~761	)

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.

Note 5−Derivative Financial Instruments

As of March 31, 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 1,614,999 MMbtu of natural gas and 15,921 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

- 8 -

Index

PDC 2005-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

~~The~~Note ~~following~~5−Derivative ~~table~~Financial ~~summarizes the location and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets.~~Instruments

			Fair Value
Derivative instruments not designated as hedge (1):		Balance Sheet Line Item	March 31, 2010			December 31, 2009
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	724,310		$	554,898
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		1,290,847			516,653
Total Derivative Assets			$	2,015,157		$	1,071,551
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(21,146	)	$	(42,274	)
	Basis protection contracts	Due to Managing General Partner-derivatives		(590,695	)		(487,277	)
	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(65,602	)		(89,584	)
	Basis protection contracts	Due to Managing General Partner-derivatives		(1,527,539	)		(1,397,638	)
Total Derivative Liabilities			$	(2,204,982	)	$	(2,016,773	)

As of June 30, 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 1,482,234 MMbtu of natural gas and 12,621 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

~~(1)~~The Asfollowing oftable ~~March~~summarizes ~~31,~~the ~~2010~~line item and ~~December~~fair ~~31,~~value ~~2009,~~amounts ~~none~~ of the Partnership’s derivative instruments ~~were~~in ~~designated~~the ~~hedges~~accompanying balance sheets.

The following 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.

			Fair Value
		Balance Sheet	June 30,			December 31,
Derivative instruments not designated as hedge (1):		Line Item	2010			2009

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	625,669		$	554,898

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		1,219,969			516,653


Total Derivative Assets			$	1,845,638		$	1,071,551

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(22,947	)	$	(42,274	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(470,961	)		(487,277	)

	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(26,128	)		(89,584	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(1,249,153	)		(1,397,638	)

Total Derivative Liabilities			$	(1,769,189	)	$	(2,016,773	)

	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	$	431,627		$	34,428	$	466,055	$	739,077		$	155,520		$	894,597
Unrealized (losses) gains		(431,627	)		1,187,024		755,397		(739,077	)		(195,764	)		(934,841	)
Total commodity price risk management gain (loss), net	$	-		$	1,221,452	$	1,221,452	$	-		$	(40,244	)	$	(40,244	)

(1) As of June 30, 2010 and December 31, 2009, none of the Partnership’s derivative instruments were designated as hedges.

~~Concentration~~The offollowing ~~Credit~~table ~~Risk.~~summarizes Athe ~~significant~~impact ~~component~~ of the Partnership’s ~~future liquidity is concentrated in~~ derivative instruments ~~that~~on ~~enables~~ the Partnership’s toaccompanying ~~manage~~statements ~~a portion~~ of ~~its~~operations ~~exposure~~for tothe ~~price~~three ~~volatility from producing natural gas~~ and ~~oil. These~~six ~~arrangements~~months ~~expose~~ended ~~the~~June ~~Partnership to credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions~~30, ~~who~~2010 ~~are~~and ~~also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts~~2009. ~~To date, the Partnership has experienced no counterparty default losses.~~

	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)	$	56,676		$	8,659	$	65,335	$	629,815		$	(45,082	)	$	584,733
Unrealized (losses) gains		(56,676	)		322,950		266,274		(629,815	)		(735,456	)		(1,365,271	)
Total commodity price risk management gain (loss), net	$	-		$	331,609	$	331,609	$	-		$	(780,538	)	$	(780,538	)

	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	$	285,576		$	245,814	$	531,390	$	1,182,442		$	296,888		$	1,479,330
Unrealized (losses) gains		(285,576	)		1,307,247		1,021,671		(1,182,442	)		(1,117,670	)		(2,300,112	)
Total commodity price risk management gain (loss), net	$	-		$	1,553,061	$	1,553,061	$	-		$	(820,782	)	$	(820,782	)

- 9 -

Index

PDC 2005-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2010

(unaudited)

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 13 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 perform~~profile. ~~Nonperformance~~ Liabilities isare ~~not~~accrued ~~anticipated~~when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. ~~Neither~~The Managing General Partner has evaluated this liability, for costs which might exceed the environmental-related expenditures that have been incurred and recorded at June 30, 2010, and determined it to be immaterial to the Partnership as of June 30, 2010. The Managing General Partner is not aware of any environmental claims existing as of June 30, ~~nor~~2010, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements. However, ~~have~~there ~~had~~can ~~any~~be ~~counterparty~~no ~~default~~assurance ~~losses~~that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.

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 13 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.

- 10 -

Index

PDC 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

~~Overview~~PDC Sponsored Drilling Program Acquisition Plan

PDC, ~~2005-A~~the ~~Limited~~managing ~~Partnership~~general ~~engages~~partner inof ~~the~~various ~~development~~public limited partnerships, ~~production~~has ~~and~~disclosed ~~sale~~its ofintention ~~oil~~to ~~and~~pursue ~~natural~~the ~~gas. The~~acquisition, ~~Partnership~~within ~~began~~the ~~oil~~next ~~and~~three ~~gas~~years, ~~operations~~of inthe ~~February~~remaining ~~2005~~third-party ~~and~~Investor ~~operates~~Partner 49interests ~~gross~~in ~~(44.4~~the ~~net)~~limited ~~development~~partnerships ~~wells,~~which ~~all~~PDC ofhas ~~which~~sponsored, ~~are~~including ~~currently~~PDC in2005-A ~~production~~Limited Partnership. ~~The~~(For ~~Partnership~~additional information regarding PDC’s ~~wells~~intention ~~are~~to ~~located~~pursue inacquisition ~~the~~of ~~Rocky~~PDC ~~Mountain~~sponsored ~~Region~~Partnership, inrefer ~~the~~to ~~state~~Regulation ofFD ~~Colorado. The~~disclosure ~~Managing~~included ~~General~~in ~~Partner~~Items ~~markets~~2.02 ~~the~~and/or ~~Partnership~~7.01 of PDC’s ~~natural~~Form ~~gas~~8-Ks ~~production~~dated toMarch ~~commercial~~4, ~~end~~2010, ~~users~~June 9, ~~interstate~~2010 orand ~~intrastate~~July ~~pipelines~~15, or2010, ~~local~~which ~~utilities~~information shall not, ~~primarily~~by ~~under~~reason ~~market~~of ~~sensitive~~this ~~contracts~~reference, inbe ~~which~~deemed ~~the~~to ~~price~~be ofincorporated ~~natural~~by ~~gas~~reference ~~sold~~in, ~~varies~~or asotherwise abe ~~result~~deemed to be part of, ~~market~~this ~~forces~~report.) ~~PDC~~Under the Acquisition Plan, onany ~~behalf~~offer ofwill ~~the~~be ~~Partnership~~subject ~~through~~to the ~~D&O~~terms ~~Agreement,~~and ~~may~~conditions ~~enter~~of ~~into~~a ~~multi-year~~to ~~fixed~~be ~~price~~proposed ~~contracts~~merger oragreement ~~utilize~~wherein ~~derivatives,~~the ~~including~~Partnership ~~collars,~~will ~~swaps~~merge orinto ~~basis~~PDC. The ~~protection~~transaction ~~swaps,~~will inalso ~~order~~be subject to ~~offset~~PDC ~~some~~having orsufficient ~~all~~available ofcapital and the ~~commodity~~approval ~~price~~by ~~variability~~a ~~for~~majority ~~particular~~of ~~periods~~the ofInvestor ~~time. Seasonal~~Partners’ ~~factors~~interests, ~~such~~excluding aspartnership ~~effects~~interest ofowned ~~weather~~by onPDC, ~~prices~~of ~~received~~each ~~and~~respective ~~costs~~limited ~~incurred,~~partnership. Should ~~and~~a ~~availability~~purchase ofoffer ~~pipeline~~from ~~capacity~~PDC be proposed, ~~owned~~approved by ~~PDC~~a ormajority ~~other~~of ~~third~~the ~~parties~~Partnerships’ unaffiliated limited partners, ~~may~~and ~~impact~~consummated, the ~~Partnership's~~purchase ~~results. In~~transaction ~~addition,~~would ~~both~~result ~~sales~~in ~~volumes~~a ~~and~~liquidating ~~prices~~cash ~~tend~~distribution to beall ~~affected~~partners byand ~~demand~~termination ~~factors~~of ~~with~~the aexistence ~~seasonal~~of ~~component~~the Partnership. There is no assurance that any such acquisition will occur.

~~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 Managing General Partner has developed a plan to initiate recompletion activities during 2011. 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.Overview

PDC, 2005-A Limited Partnership engages in the ~~managing~~development, ~~general~~production ~~partner~~and sale of ~~various~~oil ~~public~~and ~~limited~~natural ~~partnerships,~~gas. The ~~has~~Partnership ~~disclosed~~began ~~its~~oil ~~intention~~and togas ~~pursue~~operations in February 2005 and operates 49 gross (44.4 net) productive wells located in the ~~acquisition~~Rocky ofMountain Region in the ~~remaining~~state ~~third~~of ~~party~~Colorado. The ~~investor~~Managing ~~interests~~General inPartner markets the ~~limited~~Partnership’s ~~partnerships~~natural ~~which~~gas ~~PDC~~production ~~has~~to ~~sponsored~~commercial end users, ~~including~~interstate ~~PDC~~or ~~2005-A~~intrastate ~~Limited~~pipelines ~~Partnership. These~~or ~~purchases~~local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC ~~has~~does ~~stated~~not itcharge ~~anticipates~~an ~~might~~additional ~~occur~~fee ~~over~~for the ~~next~~marketing ~~three~~of ~~years,~~the ~~will~~natural begas ~~subject~~and tooil because these services are covered by the monthly well operating charge. PDC’s, ~~having~~on ~~sufficient~~behalf ~~available~~of ~~capital~~the ~~and~~Partnership in accordance with the ~~approval~~D&O byAgreement, ais ~~majority~~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 ~~investors’~~commodity ~~partnership~~price ~~interests~~variability for particular periods of time. Seasonal factors, ~~excluding~~such ~~partnership~~as ~~interest~~effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, ofmay ~~each~~impact ~~respective~~the ~~limited~~Partnership's ~~partnership~~results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

IfWell aRecompletion purchase offer from PDC is proposed and approved by a majority of the Partnerships’ unaffiliated limited partners, it would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership.Plan

The Managing General Partner has developed a plan to initiate recompletion activities during 2011. This plan includes notifying investor partners that in October 2010, funds to begin these recompletions may 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 that 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, 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 Partnership distributions. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions will be completed within a five year period. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. This Partnership potentially has 33 well recompletion opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to total between $5.0 million and $6.6 million. The Managing General Partner will re-evaluate the feasibility of commencing any or all of these recompletion opportunities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion.

Implementation of the Well Recompletion Plan would reduce or eliminate Partnership distributions to investors while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, it is possible that investors could have taxable income from the Partnership without any corresponding distributions in the future. Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the 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 effects of the Well Recompletion Plan.

- 11 -

Index

PDC 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Results~~Partnership ofOperating ~~Operations~~Results Overview

~~The~~Natural ~~following~~gas ~~table~~and ~~presents~~oil ~~selected~~sales ~~information~~increased ~~regarding~~48% or $0.7 million for the first six months of 2010 compared to the first six months of 2009, even though production volumes decreased 10% period-to-period. This increase was driven primarily by the improved commodity price environment and the increase in the Partnership’s ~~results~~oil production as a percentage of ~~operations~~total production. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.43 for the current year period compared to $3.32 for the same period a year ago. Realized derivative gains from natural gas and oil sales contributed an additional $1.30 per Mcfe or $0.5 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 to $6.73 for the current year six months from $6.60 for the same prior year period.

	Three months ended March 31,
	2010		2009		Change
Number of producing wells (end of period)		49		49		-
Production: (1)
Natural gas (Mcf)		164,223		190,448		-14	%
Oil (Bbl)		6,565		7,855		-16	%
Natural gas equivalents (Mcfe) (2)		203,613		237,578		-14	%
Mcfe per day		2,262		2,640
Natural Gas and Oil Sales
Natural gas	$	808,795	$	582,599		39	%
Oil		477,881		281,093		70	%
Total natural gas and oil sales	$	1,286,676	$	863,692		49	%
Realized Gain on Derivatives, net (3)
Natural gas	$	419,843	$	715,427		-41	%
Oil		46,212		179,170		-74	%
Total realized gain on derivatives, net	$	466,055	$	894,597		-48	%
Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	4.92	$	3.06		61	%
Oil (per Bbl)		72.79		35.79		103	%
Natural gas equivalents (per Mcfe)		6.32		3.64		74	%
Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	7.48	$	6.82		10	%
Oil (per Bbl)		79.83		58.59		36	%
Natural gas equivalents (per Mcfe)		8.61		7.40		16	%
Average Lifting Cost (per Mcfe) (4)	$	1.31	$	1.34		-2	%
Operating costs and expenses:
Direct costs - general and administrative	$	35,226	$	151,967		-77	%
Depreciation, depletion and amortization	$	718,974	$	1,082,145		-34	%
Cash distributions	$	1,277,754	$	947,770		35	%

The increase in total revenues did not have a corresponding impact on costs and expenses as natural gas and oil production costs and general and administrative expense decreased by $0.3 million for the current year six months compared to the same prior year period. The decrease is primarily due to a reduction in professional fees in the 2010 period compared to the 2009 period.

(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 represent realized derivative gains related to natural gas and oil sales.

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

- 12 -

Index

PDC 2005-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 June 30,							Six months ended June 30,
	2010		2009		Change			2010		2009		Change
Number of producing wells (end of period)		49		49		-			49		49		-

Production (1)
Natural gas (Mcf)		167,190		181,548		-8	%		331,413		371,996		-11	%
Oil (Bbl)		6,129		5,248		17	%		12,694		13,103		-3	%
Natural gas equivalents (Mcfe) (2)		203,964		213,036		-4	%		407,577		450,614		-10	%

Natural Gas and Oil Sales
Natural gas	$	486,727	$	346,515		40	%	$	1,295,522	$	929,114		39	%
Oil		440,121		285,381		54	%		918,002		566,474		62	%
Total natural gas and oil sales	$	926,848	$	631,896		47	%	$	2,213,524	$	1,495,588		48	%

Realized Gain on Derivatives, net
Natural gas	$	15,939	$	466,683		-97	%	$	435,782	$	1,182,110		-63	%
Oil		49,396		118,050		-58	%		95,608		297,220		-68	%
Total realized gain on derivatives, net	$	65,335	$	584,733		-89	%	$	531,390	$	1,479,330		-64	%

Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	2.91	$	1.91		52	%	$	3.91	$	2.50		56	%
Oil (per Bbl)		71.81		54.38		32	%		72.32		43.23		67	%
Natural gas equivalents (per Mcfe)		4.54		2.97		53	%		5.43		3.32		64	%

Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.01	$	4.48		-33	%	$	5.22	$	5.68		-8	%
Oil (per Bbl)		79.87		76.87		4	%		79.85		65.92		21	%
Natural gas equivalents (per Mcfe)		4.86		5.71		-15	%		6.73		6.60		2	%

Average Lifting Cost (per Mcfe) (3)	$	1.64	$	1.92		-14	%	$	1.48	$	1.61		-8	%

Operating costs and expenses
Direct costs - general and administrative	$	43,585	$	116,902		-63	%	$	78,811	$	268,869		-71	%
Depreciation, depletion and amortization	$	712,258	$	858,715		-17	%	$	1,431,232	$	1,940,860		-26	%

Cash distributions	$	1,051,926	$	1,658,732		-37	%	$	2,329,680	$	2,606,502		-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)

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

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

- 13 -

Index

PDC 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Natural Gas and Oil Sales

~~The~~Six ~~$0.4~~months ~~million,~~ended orJune ~~49%~~30, ~~increase in total sales 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 of 74%~~30, which was partially offset by production volume decreases of 14% on an Mcfe, or energy equivalency basis, during the 2010 three month period compared to the prior year period. Average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.32 for the current year quarter compared to $3.64 for the same quarter a year ago.2009

The $0.7 million, or 48% increase in ~~natural~~total ~~gas~~sales ~~revenues~~for ofthe ~~39%~~2010 ~~contrasts~~six month period as compared to the ~~more~~prior ~~significant~~year ~~increase~~period, inwas ~~oil~~primarily ~~revenues~~a reflection of ~~70%.~~the ~~The~~significantly ~~Partnership’s~~higher ~~oil~~average ~~revenue~~sales ~~increase~~price per Mcfe of 64%, which was ~~bolstered~~partially offset by ~~improved~~a ~~average~~production ~~oil~~volume ~~sales~~decrease ~~prices~~of ~~(103~~10%). The asaverage ~~compared~~sales toprice per Mcfe, excluding the ~~more~~impact ~~moderate,~~of ~~yet~~realized ~~significant~~derivative gains, ~~increase~~was in$5.43 ~~natural~~for ~~gas~~the ~~sales~~current ~~prices~~year ~~(61%)~~six ~~during~~month period compared to $3.32 for the same period a year ago.

The ~~Partnership~~increase ~~expects~~in tonatural ~~experience~~gas ~~continued~~revenues ~~declines~~of in39% ~~both~~contrasts ~~natural~~to ~~gas~~the ~~and~~more significant increase in oil ~~production~~revenues ~~volumes~~of ~~over~~62%. ~~the~~The ~~wells~~Partnership’s ~~life~~oil ~~cycles~~revenue ~~until~~increase ~~such~~benefited ~~time~~from rising commodity prices of 67% that ~~the~~were partially offset by lower Partnership’s ~~Wattenberg~~oil ~~wells~~production ~~may~~volumes, beper ~~successfully~~Bbl ~~recompleted~~of 3%. ~~Subsequent~~This compares to the more moderate natural gas revenue increase in which the rise in commodity prices of 56% were partially offset by a ~~successful~~steeper ~~recompletion,~~decline in natural gas production ~~will~~volumes, ~~once~~per ~~again~~Mcf beof ~~expected~~11% toduring ~~decline~~the current six month period.

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

The $0.3 million, or 47% 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 53%, which was partially offset by production volume decrease of 4%. Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $4.54 for the current year quarter compared to $2.97 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 ~~the~~ 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.

- 1314 -

Index

PDC 2005-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	$	4649,~~212~~396		$	~~179~~118,~~170~~050		$	95,608		$	297,220
Natural Gas		~~419~~15,~~843~~939			~~715~~466,~~427~~683			435,782			1,182,110
Total realized gain, net		~~466~~65,~~055~~335			~~894~~584,~~597~~733			531,390			1,479,330
Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized		(431,627	)		(739,077	)
Reclassification of realized gains included in prior periods unrealized		(56,676	)		(629,815	)		(285,576	)		(1,182,442	)
Unrealized gain (loss) for the period		1322,~~187,024~~950			(~~195~~735,~~764~~456	)		1,307,247			(1,117,670	)
Total unrealized gain (loss), net		~~755~~266,~~397~~274			(~~934~~1,~~841~~365,271	)		1,021,671			(2,300,112	)
Commodity price risk management gain (loss), net	$	1331,~~221,452~~609		$	(40780,~~244~~538	)	$	1,553,061		$	(820,782	)

~~Realized~~Six ~~gains~~months ~~recognized~~ended inJune ~~the~~30, ~~first quarter of~~ 2010 ~~which~~as ~~total $0.5 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 $1.2 million, $1.4 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~~$0.5 ~~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 the derivative position. For the six month period, realized gains related to natural gas and oil derivatives were $0.26 million ~~was~~and ~~comprised~~$0.1 ofmillion, arespectively, ~~decrease~~and inrealized ~~fair~~losses ~~value~~on of the Partnership’s CIG basis swaps ofwere $0.82 million. Unrealized ~~which~~gains ~~resulted~~for ~~from~~the asix ~~steeper~~months ~~decline~~period, inwere ~~NYMEX~~$1.3 ~~pricing~~million ~~relative~~due primarily to ~~CIG~~a ~~pricing~~downward ~~that~~shift ~~was~~in ~~partially~~the ~~offset~~natural bygas aand ~~$0.6~~oil ~~million~~forward ~~net~~curves. Unrealized ~~unrealized~~gains ~~gain~~on ~~from~~ the Partnership’s ~~commodity~~natural ~~derivatives~~gas and oil positions for the period were $1.2 million and $0.1 million, respectively.

~~Realized~~For ~~derivative~~the ~~gains,~~2009 ~~down~~six ~~48%~~month ~~from~~period, the ~~prior~~Partnership ~~year~~realized ~~first~~significant ~~quarter,~~derivative ~~contributed~~gains anas ~~additional~~a ~~$2.29~~result ~~per~~of ~~Mcfe~~lower 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 ~~16%~~the toforward ~~$8.61~~basis ~~for~~differential during the ~~current~~period ~~year~~between ~~quarter~~NYMEX ~~from~~and ~~$7.40~~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 $0.1 million. 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 approximately $0.3 million and realized losses on the Partnership’s CIG basis swaps were $0.2 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 $0.2 million, respectively.

- 15 -

Index

PDC 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~The~~For ~~following~~the ~~table~~2009 ~~presents~~second quarter, the Partnership’s realized significant derivative ~~positions~~gains inas ~~effect~~a 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
Commodity/	Quantity (Gas-		Weighted Average Contract Price				Quantity (Gas-Mmbtu		Weighted Average Contract		Quantity (Gas-		Weighted Average Contract			Fair Value at March 31,
Index	Mmbtu)		Floors		Ceilings		Oil-Bbls)		Price		Mmbtu)		Price			2010(1)
Natural Gas
CIG
10/01 - 12/31/2010		35,710	$	4.75	$	9.45		-	$	-		-	$	-		$	23,186
01/01 - 03/31/2011		53,565		4.75		9.45		-		-		-		-			25,413
NYMEX
04/01 - 06/30/2010		-		-		-		132,765		5.55		127,368		(1.88	)		28,152
07/01 - 09/30/2010		-		-		-		130,629		5.56		124,865		(1.88	)		(5,485	)
10/01 - 12/31/2010		15,514		5.75		8.30		72,654		6.07		85,961		(1.88	)		(960	)
01/01 - 03/31/2011		21,022		5.75		8.30		38,758		6.81		59,780		(1.88	)		(16,022	)
04/01 - 12/31/2011		-		-		-		333,231		6.77		333,231		(1.88	)		(5,466	)
2012-2013		28,595		6.00		8.27		752,556		7.05		781,150		(1.88	)		(231,224	)
Total Natural Gas		154,406						1,460,593				1,512,355					(182,406	)
Oil
NYMEX
04/01 - 06/30/2010		-		-		-		3,300		92.96		-		-			28,524
07/01 - 09/30/2010		-		-		-		3,336		92.96		-		-			26,184
10/01 - 12/31/2010		-		-		-		3,336		92.96		-		-			24,621
01/01 - 03/31/2011		-		-		-		1,476		70.75		-		-			(21,146	)
04/01 - 12/31/2011		-		-		-		4,473		70.75		-		-			(65,602	)
Total Oil		-						15,921				-					(7,419	)
Total Natural Gas and Oil																$	(189,825	)

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/	Quantity (Gas-		Weighted Average Contract Price				Quantity (Gas-Mmbtu		Weighted Average Contract		Quantity (Gas-		Weighted Average Contract			Fair Value at June 30,
Index	Mmbtu)		Floors		Ceilings		Oil-Bbls)		Price		Mmbtu)		Price			2010(1)

Natural Gas
CIG
10/01 - 12/31/2010		35,710	$	4.75	$	9.45		-	$	-		-	$	-		$	21,796
01/01 - 03/31/2011		53,565		4.75		9.45		-		-		-		-			26,693

NYMEX
07/01 - 09/30/2010		-		-		-		130,629		5.56		124,865		(1.88	)		(27,899	)
10/01 - 12/31/2010		15,514		5.75		8.30		72,654		6.07		85,961		(1.88	)		(2,620	)
01/01 - 03/31/2011		21,022		5.75		8.30		38,758		6.81		59,780		(1.88	)		(9,482	)
04/01 - 06/30/2011		-		-		-		113,252		6.78		113,252		(1.88	)		40,336
07/01 - 12/31/2011		-		-		-		219,979		6.76		219,979		(1.88	)		3,670
2012-2013		28,595		6.00		8.27		752,556		7.05		781,150		(1.88	)		(32,855	)
Total Natural Gas		154,406						1,327,828				1,384,987					19,639

Oil
NYMEX
07/01 - 09/30/2010		-		-		-		3,336		92.96		-		-			55,169
10/01 - 12/31/2010		-		-		-		3,336		92.96		-		-			50,716
01/01 - 03/31/2011		-		-		-		1,476		70.75		-		-			(10,837	)
04/01 - 06/30/2011		-		-		-		1,487		70.75		-		-			(12,110	)
07/01 - 12/31/2011		-		-		-		2,986		70.75		-		-			(26,128	)
Total Oil		-						12,621				-					56,810

Total Natural Gas and Oil																$	76,449

(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 2010 three month period compared to 2009 three month period, oil and natural production, on an energy equivalency~~-~~basis,~~ decreased 33,965 Mcfe, or 14%, due to normally-occurring production declines throughout an oil and natural gas well’s production life cycle in addition to temporary operational constraints during the current quarter at most Grand Valley Field and some Wattenberg Field Partnership wells. Production and operating costs were lower by approximately $0.1 million, or 16% ~~due in part, to volume~~-associated reductions in production taxes and lease operating expenses. 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 $1.31 for the 2010 three month period compared to $1.34 for the comparable 2009 three month period.

- 15 -

Index

PDC 2005-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 10%, which reflects in part, the normally-occurring production declines throughout a natural gas and oil well’s production life cycle. Additionally, Grand Valley Field operational constraints on most wells, also contributed to the production decline during the current period. Production and operating costs were lower by approximately $0.1 million or 17%, due in part, to lower lease operating expenses due to the Managing General Partner’s cost cutting initiatives partially offset by increased production taxes due to higher commodity valuations. Additionally, 2010 well operations costs rose 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 $1.48 for the six months ended June 30, of 2010 compared to $1.61 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 4%, primarily as a result of the Partnership wells’ expected normally-occurring production life-cycle declines. Production and operating costs were lower by approximately $0.1 million, or 18% due to lower lease operating costs that were partially offset by higher production taxes and well operations fees, as noted above. Production and operating costs per Mcfe were $1.64 and $1.92 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 $0.1 million principally due to reduced 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 $0.2 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~~Six ~~DD&A~~months ~~expense~~ended ~~rate~~June ~~per~~30, ~~Mcfe decreased to $3.53 for the~~ 2010 ~~three month period, compared to $4.55 during the same period in 2009~~ as calculated by the respective methodologies described above. In addition, an out of period expense recorded in the first quarter of 2009 increased DD&A expense by approximately $106,000. The variance in the per Mcfe rates for the 2010 period compared to ~~the~~six ~~2009~~months ~~period~~ended isJune ~~partially the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley fields~~30, ~~which have significantly different DD&A rates, in addition to the effects of reserve revisions at December 31,~~ 2009 compared to December 31, 2008 in which proved developed producing downward revisions in the Partnership’s Grand Valley Field were offset by upward proved developed producing revisions in its Wattenberg Field. These decreased rates, combined with lower production volumes, resulted in the in DD&A expense reduction of approximately $0.4 million for the 2010 three month period compared to the same 2009 period.

The DD&A expense rate per Mcfe decreased to $3.51 for the 2010 six month period, compared to $4.31 during the same period in 2009, as calculated by the respective methodologies described above. The decrease 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. This was effected by field-level depletion rate changes due to reserve revisions at December 31, 2009 compared to December 31, 2008, in which proved developed producing downward revisions in the Partnership’s Grand Valley Field were offset by upward proved developed producing revisions in its Wattenberg Field. The decreased DD&A expense rate, combined with the production declines noted in previous sections, resulted in a decreased DD&A expense of approximately $0.5 million for the 2010 six month period compared to the same 2009 period. During the 2009 six month period, an out of period expense recorded in the first quarter of 2009 increased DD&A expense by approximately $106,000.

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Index

PDC 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

The DD&A expense rate per Mcfe decreased to $3.49 for the 2010 second quarter, compared to $4.03 during the same quarter in 2009 as calculated by the respective methodologies described above. The decrease 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 changes in field-level depletion rates, noted above. The lower DD&A expense rate, combined with the effect of the production declines noted in previous sections, resulted in the DD&A expense reduction of $0.1 million 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 7774% of expected natural gas production and 7071% of expected oil production for the remainder of 2010, at an average price of $34.8405 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 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 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

Working capital at ~~March~~June 3130, 2010 was $10.28 million compared to working capital of $1.0 million at December 31, 2009. This ~~increase~~decrease of approximately $0.2 million was primarily due to the following changes in accounts receivable or payable balances:

· Natural gas and oil receivables ~~remained~~decreased ~~unchanged~~to at $0.86 million as of ~~March~~June 3130, 2010, ~~and~~from $0.8 million as of December 31, 2009.

· Realized derivative gains receivables decreased to approximately $0.31 million as of ~~March~~June 3130, 2010, from $0.4 million as of December 31, 2009.

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

· Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, decreased to a $0.2 million liability as of ~~March~~June 3130, 2010, from a $0.4 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 $613,000 and $1618,000 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 September 2005 and has distributed $4142.34 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 ended June 30,		Managing General Partner Distributions			Investor Partners Distributions			Total Distributions
2010	$	~~255,551~~$	210,385	$	~~1,022,203~~$	841,541	$	~~1,277,754~~$	1,051,926
2009	$	~~189,553~~$	331,745	$	~~758,217~~$	1,326,987	$	~~947,770~~$	1,658,732
Six months ended June 30,		Managing General Partner Distributions			Investor Partners Distributions			Total Distributions
2010		$	465,936		$	1,863,744		$	2,329,680
2009		$	521,299		$	2,085,203		$	2,606,502

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Index

PDC 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Cash Flows From Operating Activities

Net cash provided by operating activities was $12.3 million for the ~~three~~six months ended ~~March~~June 3130, 2010, compared to $12.06 million for the comparable period in 2009. The approximately $0.3 million ~~increase~~decrease in cash provided by operating activities was due primarily to the following:

· ~~Increases~~An increase in natural gas and oil sales receipts of $0.47 million, or 39%, accompanied by decreases in ~~production~~natural gas and ~~operating~~oil ~~cost~~production costs of approximately $0.1 million or 17% and direct costs – general and administrative of $0.12 million, ~~offset~~or by17%;

· ~~Decreases~~A decrease in commodity price risk management realized gains receipts of $0.28 million, or 46%; and

· A decrease in the liability Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, of approximately $0.25 million.

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 2005-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 2005-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 September 2008, 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. ~~There were no limited partnership units repurchased by PDC for the three months ended March 31, 2010.~~

The following table presents information about the Managing General Partner’s limited partner unit repurchases during the three months ended June 30, 2010.

Period	Total Number of Units Repurchased		Average Price Paid per Unit

April 1−30, 2010		-	$	-
May 1−31, 2010		-		-
June 1−30, 2010		0.25		4,800
Total second quarter Unit Repurchase Program repurchases		0.25

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 2005-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.

Exhibits

(a)	Exhibit Index.

Incorporated by Reference

~~Incorporated by Reference~~

Exhibit Number

Exhibit Description

~~Exhibit Description~~

Form

~~Form~~

SEC File Number

~~SEC File Number~~

Exhibit

~~Exhibit~~

Filing Date

~~Filing Date~~

Filed Herewith

~~Filed Herewith~~

3.1

Limited Partnership Agreement (filed by PDC as Managing General Partner for PDC 2004-2006 Drilling Program)

~~Limited Partnership Agreement~~

S-1 Post-Effective Amend 2

~~10-12G/A Amend 1~~

333-111260

~~000-53201~~

Appendix A

06/29/2005

~~08/06/2008~~

3.2

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

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

10-K

~~10-12G/A Amend 1~~

000-51309

~~000-53201~~

3.2

~~3.1~~

02/26/2009

~~08/06/2008~~

10.2

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

10-12G/A Amend 1

000-53201

10.2

08/06/2008

10.1

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

10-K

000-51309

10.1

02/26/2009

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 2005-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 2005-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 13, 2010

By its Managing General Partner

Petroleum Development Corporation

By: /s/ Richard W. McCullough

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 13, 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 13, 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 13, 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 2005-A Limited Partnership