CONFORMED COPY

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

~~Washington~~WASHINGTON, ~~D.C.~~DC 20549

FORM 10-Q

~~[X]~~x QUARTERLY ~~Quarterly~~REPORT ~~Report Pursuant~~PURSUANT toTO ~~Section~~SECTION 13 or 15(d) ofOF THE SECURITIES EXCHANGE ACT OF 1934

For the ~~Securities Exchange~~quarterly ~~Act~~period ofended June ~~1934~~30, 2010

For the period ended June 30, 2005

[o ]TRANSITION ~~Transition Report~~REPORT ~~Pursuant~~PURSUANT toTO ~~Section~~SECTION 13 ofOR 15(d) ofOF THE SECURITIES EXCHANGE ACT OF 1934

~~the~~FOR ~~Securities Exchange~~THE ~~Act~~TRANSITION ofPERIOD ~~1934~~____________ TO ____________

~~For~~Commission ~~the~~File ~~transition period~~Number ~~from to~~000-50615

~~Commission~~PDC ~~file number 000~~2003-~~50615~~A Limited Partnership (Exact name of registrant as specified in its charter)

West Virginia (State or other jurisdiction of incorporation or organization) 51-0452053 (I.R.S. Employer Identification ~~Number~~ ~~30-0059674~~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 o No x

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 x

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

As of June 30, 2010 the Partnership had 424.15 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~103~~INDEX ~~East~~TO ~~Main Street~~REPORT ON FORM 10-Q

Bridgeport, WV 26330

		Page
PART I – FINANCIAL INFORMATION

	Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	2
	Condensed Statements of Operations (unaudited)	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22
Item 4.	Controls and Procedures	22

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	23
Item 1A.	Risk Factors	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	23
Item 3.	Defaults Upon Senior Securities	23
Item 4.	[Removed and Reserved]	23
Item 5.	Other Information	23
Item 6.	Exhibits	24

	SIGNATURES	25

~~Telephone: (304) 842-6256~~Index

~~Indicate~~NOTE byREGARDING ~~check~~FORWARD-LOOKING mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes XX No STATEMENTS

~~Indicate~~This byperiodic ~~check~~report ~~mark~~contains ~~whether~~“forward-looking statements” within the ~~registrant~~meaning isof ~~an accelerated~~Section ~~filer~~27A of the Securities Act of 1933 (asthe ~~definition~~“Securities inAct”) ~~Rule~~and ~~12b-2~~Section 21E of the Securities Exchange Act. of 1934 (“Exchange Act”) ~~Yes No XX~~ regarding PDC 2003-A Limited Partnership’s (the “Partnership” or the “Registrant”) 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”) 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;

●

changes in estimates of proved reserves;

●

declines in the values of the Partnership’s natural gas and oil properties resulting from impairments;

●

the timing and extent 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 refracturing and operation of natural gas and oil wells;

●

future production and refracturing costs;

●

the availability of Partnership future cash flows for investor distributions or funding of Well Refracturing 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;

●

the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers under the Acquisition Plan, and the timing of consummating any such mergers if at all;

●

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 reports on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission, or SEC, on October 12, 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 made. 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

Item1.

Financial Statements (unaudited)

PDC 2003-A Limited Partnership

Condensed Balance Sheets

(unaudited)


	June 30, 2010			December 31, 2009*
Assets

Current assets:
Cash and cash equivalents	$	85		$	133
Accounts receivable		55,382			64,246
Oil inventory		12,166			11,442
Due from Managing General Partner-derivatives		101,549			94,751
Due from Managing General Partner-other, net		—			8,289
Total current assets		169,182			178,861


Natural gas and oil properties, successful efforts method, at cost		9,362,490			9,361,153
Less: Accumulated depreciation, depletion and amortization		(5,548,305	)		(5,344,051	)
Oil and gas properties, net		3,814,185			4,017,102

Due from Managing General Partner-derivatives		181,953			76,808
Other assets		22,537			19,132
Total noncurrent assets		4,018,675			4,113,042

Total Assets	$	4,187,857		$	4,291,903

Liabilities and Partners’ Equity

Current liabilities:
Accounts payable and accrued expenses	$	6,124		$	7,588
Due to Managing General Partner-derivatives		73,682			73,549
Due to Managing General Partner-other, net		29,921			—
Total current liabilities		109,727			81,137

Due to Managing General Partner-derivatives		194,258			234,481
Asset retirement obligations		114,995			111,671
Total liabilities		418,980			427,289

Commitments and contingent liabilities

Partners’ equity:
Managing General Partner		755,068			774,216
Limited Partners - 424.15 units issued and outstanding		3,013,809			3,090,398
Total Partners’ equity		3,768,877			3,864,614

Total Liabilities and Partners’ Equity	$	4,187,857		$	4,291,903

________________________________

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-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	$	166,053	$	155,517		$	383,668	$	300,471
Commodity price risk management gain (loss), net		66,103		(147,631	)		235,223		(151,639	)
Total revenues		232,156		7,886			618,891		148,832

Operating costs and expenses:
Natural gas and oil production costs		61,597		69,931			117,885		142,675
Direct costs - general and administrative		1,374		5,457			2,264		26,654
Depreciation, depletion and amortization		98,829		195,788			204,254		386,447
Accretion of asset retirement obligations		1,674		1,205			3,324		2,410
Total operating costs and expenses		163,474		272,381			327,727		558,186

(Loss) income from operations		68,682		(264,495	)		291,164		(409,354	)

Interest income		—		4,057			—		8,174

Net (loss) income	$	68,682	$	(260,438	)	$	291,164	$	(401,180	)

Net (loss) income allocated to partners	$	68,682	$	(260,438	)	$	291,164	$	(401,180	)
Less: Managing General Partner interest in net (loss) income		13,737		(52,088	)		58,233		(80,236	)
Net (loss) income allocated to Investor Partners	$	54,945	$	(208,350	)	$	232,931	$	(320,944	)

Net (loss) income per Investor Partner unit	$	130	$	(491	)	$	549	$	(757	)

Investor Partner units outstanding		424.15		424.15			424.15		424.15

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-A Limited Partnership

Condensed Statements of Cash Flows

(unaudited)


	Six months ended June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	291,164		$	(401,180	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		204,254			386,447
Accretion of asset retirement obligations		3,324			2,410
Unrealized (gain) loss on derivative transactions		(152,033	)		382,015
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		8,864			(5,921	)
(Increase) decrease in oil inventory		(724	)		7,380
Increase in other assets		(3,405	)		(3,760	)
Decrease in accounts payable and accrued expenses		(1,464	)		(4,566	)
Increase in Due to Managing General Partner - other, net		29,921			—
Decrease in Due from Managing General Partner - other, net		8,289			178,664
Net cash provided by operating activities		388,190			541,489

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(1,337	)		(24,119	)
Net cash used in investing activities		(1,337	)		(24,119	)

Cash flows from financing activities:
Distributions to Partners		(386,901	)		(517,041	)
Net cash used in financing activities		(386,901	)		(517,041	)

Net (decrease) increase in cash and cash equivalents		(48	)		329
Cash and cash equivalents, beginning of period		133			36,809
Cash and cash equivalents, end of period	$	85		$	37,138

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2003-A Limited Partnership (the “Partnership”) was organized as a limited partnership on June 3, 2002, 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 April 30, 2003, 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 9.0 units of limited partner interests and 415.15 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 June 30, 2010, there were 435 Investor Partners. As of June 30, 2010 the Managing General Partner has repurchased 18.34 units of the total 424.15 outstanding units of Partnership interests from Investor Partners at an average price of $8,840 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 natural gas and oil properties until such time that the Partnership’s wells are depleted or become uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, 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 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 Securities and Exchange Commission, or 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 June 30, 2010, and the cash flows for the six months ended June 30, 2010, are not necessarily indicative of the results to be expected for the full year or any other future period.

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

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

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Index

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

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

Internal Control over Financial Reporting in Exchange Act Periodic Reports

By Final Rule effective September 21, 2010, the SEC amended its rules and forms to conform them to Section 404(c) of the Sarbanes-Oxley Act of 2002, or SOX, as added by the Dodd-Frank Wall Street Reform and Consumer Protection Act. The new SEC rules exempt the Partnership, as a smaller reporting company filer, from the SOX requirement that registrants, which are accelerated or large accelerated filers, obtain and include in their annual report filed with the SEC their independent registered public accounting firm’s attestation report on the effectiveness of the registrant’s internal controls over financial reporting.

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.


	June 30, 2010			December 31, 2009

Natural gas and oil sales revenues collected from the Partnership’s third-party customers	$	54,436		$	71,800
Commodity Price Risk Management, Realized Gains		10,679			58,656
Other (1)		(95,036	)		(122,167	)
Total Due (to) from Managing General Partner-other, net	$	(29,921	)	$	8,289

(1)

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

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

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Index

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)


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

Well operations and maintenance	$	46,997	$	56,074	$	88,183	$	113,590
Gathering, compression and processing fees		5,161		5,291		10,907		11,112
Direct costs - general and administrative		1,374		5,457		2,264		26,654
Cash distributions*		39,524		66,994		90,762		120,576

*Cash distributions include $5,827 and $13,381 during the three and six months ended June 30, 2010, respectively, and $9,732 and $17,168 during the three and six months ended June 30, 2009, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

Note 4−Fair Value Measurements

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

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Index

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

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


	Quoted Prices in Active Markets (Level 1)			Significant Unobservable Inputs (Level 3)			Total

As of December 31, 2009
Assets:
Commodity based derivatives	$	77,667		$	93,892		$	171,559
Total assets		77,667			93,892			171,559

Liabilities:
Commodity based derivatives		(5,255	)		(27,897	)		(33,152	)
Basis protection derivative contracts		—			(274,878	)		(274,878	)
Total liabilities		(5,255	)		(302,775	)		(308,030	)

Net asset (liability)	$	72,412		$	(208,883	)	$	(136,471	)

As of June 30, 2010
Assets:
Commodity based derivatives	$	241,727		$	41,775		$	283,502
Total assets		241,727			41,775			283,502

Liabilities:
Commodity based derivatives		—			(15,214	)		(15,214	)
Basis protection derivative contracts		—			(252,726	)		(252,726	)
Total liabilities		—			(267,940	)		(267,940	)

Net asset (liability)	$	241,727		$	(226,165	)	$	15,562

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


	Six months ended June 30, 2010
Fair value, net liability, as of December 31, 2009	$	(208,883	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		41,121
Settlements		(58,403	)
Fair value, net liability, as of June 30, 2010	$	(226,165	)

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	$	31,813

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

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

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Index

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2010

(unaudited)

Note 5−Derivative Financial Instruments

As of June 30, 2010, the Partnership had derivative instruments, comprised of commodity collars, commodity fixed-price swaps and a basis swap, in place for a portion of its anticipated production through 2013 for a total of 215,619 MMbtu of natural gas and 3,634 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

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


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

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	101,549		$	94,751

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		181,953			76,808

Total Derivative Assets			$	283,502		$	171,559

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(6,995	)	$	(5,393	)
	Basis protection contracts	Due to Managing General Partner-derivatives		(66,687	)		(68,156	)

	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(8,219	)		(27,759	)
	Basis protection contracts	Due to Managing General Partner-derivatives		(186,039	)		(206,722	)
Total Derivative Liabilities			$	(267,940	)	$	(308,030	)

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

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


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

Commodity price risk management, net
Realized gains (losses)	$	9,094		$	4,169	$	13,263	$	101,810		$	(9,655	)	$	92,155
Unrealized (losses) gains		(9,094	)		61,934		52,840		(101,810	)		(137,976	)		(239,786	)
Total commodity price risk management gain (loss), net	$	—		$	66,103	$	66,103	$	—		$	(147,631	)	$	(147,631	)

	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	$	49,078		$	34,112	$	83,190	$	191,499		$	38,877		$	230,376
Unrealized (losses) gains		(49,078	)		201,111		152,033		(191,499	)		(190,516	)		(382,015	)
Total commodity price risk management gain (loss), net	$	—		$	235,223	$	235,223	$	—		$	(151,639	)	$	(151,639	)

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Index

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 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

Environmental

Due to the nature of the natural gas and oil business, the Partnership is exposed to environmental risks. The 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 environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. 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, 2010, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.

In December 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 natural gas and oil companies operating in the Piceance region of Colorado. Operating expenses, including this fine, if any, are allocated among the users of the road based upon their respective usage. The Partnership has three wells in this region. The Notice alleged 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 into negotiations with the CDPHE regarding this notice and a settlement was accepted by CDPHE in November 2010. This settlement did not have a material impact on the Partnership’s financial position or results of operations.

- 10 -

Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

PART I - FINANCIAL INFORMATION			Page No.
Item 1.1.	Financial Statements
		Balance Sheets - June 30, 2005 (unaudited) and December 31, 2004	1
		Statements of Operations - Three Months and Six Months Ended June 30, 2005 and 2004 (unaudited)	2
		Statement of Partners' Equity and Comprehensive Income (Loss) - Six Months Ended June 30, 2005 (unaudited)	3
		Statements of Cash Flows- Six Months Ended June 30, 2005 and 2004 (unaudited)	4
		Notes to Financial Statements (unaudited)	5
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations	6
Item 3.		Quantitative and Qualitative Disclosure About Market Risk	9
Item 4.		Controls and Procedures	10
PART II OTHER INFORMATION
Item 1.		Legal Proceedings	12
Item 6.		Exhibits	12

Partnership Overview

PDC 2003-A Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in April 2003 and operates 23 gross (11.3 net) productive wells located in the Rocky Mountain Region in the state of Colorado. In addition, two Wattenberg Field Partnership wells are temporarily not in production at June 30, 2010, which include one well (0.5 net) due to operational issues and one well (0.5 net) due to equipment problems. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership’s results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through the next three years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of that partnership other than PDC or its affiliates (“non-affiliated Investor Partners”), in the limited partnerships that PDC has sponsored, including this Partnership. For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02, 7.01 and/or 8.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010, July 15, 2010 and November 17, 2010. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement does or will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital and the approval by a majority of the limited partnerships units held by the non-affiliated Investor Partners of each respective limited partnership. Consummation of any proposed merger of a PDC sponsored limited partnership under the Acquisition Plan will likely result in the termination of the existence of that partnership and the right of non-affiliated Investor Partners to receive a cash payment for their limited partnership units in that partnership.

In June 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership (collectively, the “2004 partnerships”). PDC serves as the managing general partner of each of the 2004 partnerships. Definitive proxy statements for each of the 2004 partnerships requesting approval from the applicable non-affiliated Investor Partners for, among other things were mailed to the non-affiliated Investor Partners of the 2004 partnerships in early October 2010. Special meetings were held on December 8, 2010, at which the majority of the non-affiliated Investor Partners of each of the 2004 partnerships voted to approve the applicable merger agreement.

- 11 -

Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Balance~~In ~~Sheets~~November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, and the 2005 Rockies Region Private Limited Partnership (collectively, the “2005 partnerships”). PDC serves as the managing general partner of each of the 2005 partnerships. On December 3, 2010, each of the 2005 partnerships filed with the SEC, a preliminary proxy statement relating to such partnership’s prospective merger. Upon completion of the SEC review process, a definitive proxy statement will be mailed to the 2005 partnerships’ non-affiliated Investor Partners requesting their approval of the merger transactions. Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by the non-affiliated Investor Partners of each respective partnership, as well as, the satisfaction of other customary closing conditions, then such partnership will merge with and into a wholly-owned subsidiary of PDC. PDC has offered to pay approximately $36.4 million for the limited partnership units of the 2005 partnerships in connection with the mergers. Although there is no assurance of the likelihood or timing of the completion of the SEC proxy disclosure review process or whether the Partnership will obtain the necessary approvals from non-affiliated investors, each merger of the 2005 partnerships is expected to close during the first half of 2011.

~~June~~The 30feasibility and timing of any future purchase offer by PDC to any additional partnership, ~~2005~~including this Partnership, depends on that partnership’s suitability in meeting a set of criteria that includes, but is not limited to, the following: age and ~~December~~productive-life 31stage characteristics of the partnership’s well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated to gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any merger and acquisition will occur, ~~2004~~as a result of PDC’s proposed repurchase offers to the 2005 partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.

Assets
	2005	2004
	(Unaudited)
Current assets:
Cash	$ 2,248	4,535
Accounts receivable - oil and gas revenues	365,397	506,920
Total current assets	367,645	511,455
Oil and gas properties, successful efforts method	9,231,819	9,231,819
Less accumulated depreciation, depletion
and amortization	2,036,349	1,710,621
	7,195,470	7,521,198
	$ 7,563,115	8,032,653
Liabilities and Partners' Equity
Current liabilities:
Accrued expenses	$ 79,906	113,182
Total current liabilities	79,906	113,182
Asset retirement obligations	7,394	7,178
Partners' Equity	7,475,815	7,912,293
	$ 7,563,115	8,032,653

Well Refracturing Plan

~~See~~The ~~accompanying~~Managing ~~notes~~General Partner has prepared a plan for the Partnership’s Wattenberg Field wells that were initially completed in the Codell producing formation during the Partnership’s initial development (the “Well Refracturing Plan”). Under the Well Refracturing Plan, the Partnership plans to initiate ~~financial~~Codell ~~statements~~formation refracturing activities during 2011. These refracturing, or “refracing,” activities will consist of a second hydraulic fracturing treatment to the currently producing Codell formation.

During the fourth quarter 2010, the Managing General Partner began withholding funds from several of the PDC sponsored partnerships, on a pro-1-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows resulting from current production. The funds retained are necessary for the Partnership to pay for refracturing 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 refractured, the Partnership will experience a reduction in proved natural gas and oil reserves currently assigned to these wells. Both the number and timing of refracturings will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing costs and projected cash withholding, all Partnership refracturings will be completed within a five year period. This Partnership has not begun to withhold funds for this additional Codell formation development as this Partnership has outstanding payables to the General Partner.

Current estimated costs for these well refracturings are between $150,000 and $200,000 per refracturing. This Partnership potentially has 22 well refracturing opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $1.6 million and $2.2 million. The Managing General Partner will continually evaluate the timing of commencing these refracturings based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the refracturing.

Implementation of the Well Refracturing Plan would reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners 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 Refracturing 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 Refracturing Plan.

- 12 -

Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Statements~~Partnership ~~of Operations~~Operating Results Overview

~~Three~~Natural ~~Months~~gas and ~~Six Months~~oil ~~ended~~sales ~~June~~increased 3028% or $0.1 million for the first six months of 2010 compared to the first six months of 2009, ~~2005~~even though production volumes decreased 19% period-to-period. This increase was driven primarily by the improved commodity price environment. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.11 for the current year period compared to $3.89 for the same period a year ago. Realized derivative gains from natural gas and ~~2004~~oil sales contributed an additional $1.32 per Mcfe or $0.1 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 $7.43 for the current year six months from $6.88 for the same prior year period.

~~(Unaudited)~~- 13 -

	Three Months Ended June 30,		Six Months Ended June 30,
	2005	2004	2005	2004
Revenues:
Sales of oil and gas	$ 493,765	674,482	970,275	1,363,873
Interest income	912	301	1,402	506
	494,677	674,783	971,677	1,364,379
Expenses:
Lifting cost	84,453	110,794	164,473	210,434
Direct administration cost	124	-	232	-
Depreciation, depletion, and amortization	159,787	257,075	325,728	527,576
	244,364	367,869	490,433	738,010
Net income	$ 250,313	306,914	481,244	626,369
Net income per limited partner unit	$ 472	579	908	1,181

Index

See accompanying notes to financial statements.

-2-

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Statement~~Results of ~~Partners'~~ ~~Equity and Comprehensive Income (Loss)~~Operations

~~Six~~The ~~months~~following ~~ended~~table ~~June~~presents ~~30,~~selected ~~2005~~information regarding the Partnership’s results of operations.

(Unaudited)

	Three months ended June 30,							Six months ended June 30,
	2010		2009		Change			2010		2009		Change
Number of producing wells (end of period)		23		23		—			23		23		—

Production (1)
Natural gas (Mcf)		23,244		27,747		-16	%		47,288		57,581		-18	%
Oil (Bbl)		1,209		1,750		-31	%		2,585		3,264		-21	%
Natural gas equivalents (Mcfe) (2)		30,498		38,247		-20	%		62,798		77,165		-19	%

Natural Gas and Oil Sales
Natural gas	$	79,554	$	61,020		30	%	$	197,867	$	151,640		30	%
Oil		86,499		94,497		-8	%		185,801		148,831		25	%
Total natural gas and oil sales	$	166,053	$	155,517		7	%	$	383,668	$	300,471		28	%

Realized Gain on Derivatives, net
Natural gas	$	—	$	62,135		-100	%	$	57,518	$	154,793		-63	%
Oil		13,263		30,020		-56	%		25,672		75,583		-66	%
Total realized gain on derivatives, net	$	13,263	$	92,155		-86	%	$	83,190	$	230,376		-64	%

Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	3.42	$	2.20		56	%	$	4.18	$	2.63		59	%
Oil (per Bbl)		71.55		54.00		32	%		71.88		45.60		58	%
Natural gas equivalents (per Mcfe)		5.44		4.07		34	%		6.11		3.89		57	%

Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.42	$	4.44		-23	%	$	5.40	$	5.32		1	%
Oil (per Bbl)		82.52		71.15		16	%		81.81		68.75		19	%
Natural gas equivalents (per Mcfe)		5.88		6.48		-9	%		7.43		6.88		8	%

Average Lifting Cost (per Mcfe) (3)	$	2.02	$	1.83		10	%	$	1.88	$	1.85		2	%

Operating costs and expenses
Direct costs - general and administrative	$	1,374	$	5,457		-75	%	$	2,264	$	26,654		-92	%
Depreciation, depletion and amortization	$	98,829	$	195,788		-50	%	$	204,254	$	386,447		-47	%

Cash distributions	$	168,482	$	286,308		-41	%	$	386,901	$	517,041		-25	%

	Limited Partners	Managing General Partner	Accumulated Other Comprehensive Income (loss)	Total
Balance December 31, 2004	$6,377,933	1,594,486	(60,126)	7,912,293
Distributions to partners	(725,736)	(181,432)	-	(907,168)
Comprehensive income:
Net income	384,995	96,249	-	481,244
Change in fair value of outstanding hedging positions			(44,542)
Less reclassification adjustments for settled contracts included in net income			33,988
Other comprehensive loss			(10,554)	(10,554)
Comprehensive income				470,690
Balance June 30, 2005	$ 6,037,192	1,509,303	(70,680)	7,475,815

*Percentage change not meaningful, equal to or greater than 250% or not calculable. Amounts may not calculate due to rounding.

~~See accompanying notes to financial statements.~~______________

~~-3-~~(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)

Lifting 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

- 14 -

Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Statements~~Natural ofGas ~~Cash Flows~~and Oil Sales

Six ~~Months~~months ended June 30, ~~2005~~2010 ~~and~~as ~~2004~~compared to six months ended June 30, 2009

~~(Unaudited)~~The $0.1 million, or 28% increase in sales for the 2010 six month period as compared to the prior year period, was primarily a reflection of the significantly higher average sales price per Mcfe of 57%, which was partially offset by a production volume decrease of 19%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.11 for the current year six month period compared to $3.89 for the same period a year ago.

	2005	2004
Cash flows from operating activities:
Net income	$481,244	626,369
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	325,728	527,576
Accretion of asset retirement obligations	216	-
Changes in operating assets and liabilities:
Decrease in accounts receivable - oil and gas revenues	104,572	344,322
Decrease in accounts payable	(6,879)	(5,029)
Net cash provided from operating activities	904,881	1,493,238
Cash flows from financing activities:
Distributions to partners	(907,168)	(1,496,960)
Net cash used by financing activities	(907,168)	(1,496,960)
Net decrease in cash	(2,287)	(3,722)
Cash at beginning of period	4,535	7,660
Cash at end of period	$ 2,248	3,938

Natural gas and oil revenues increased by 30% and 25%, respectively. The Partnership’s natural gas revenue increase resulted from rising commodity prices per Mcf, of 59%, which were partially offset by lower Partnership natural gas production volumes of 18%. This compares to the more moderate oil revenue increase in which the rise in commodity prices per Bbl, of 58% was partially offset by a steeper decline in oil production volumes of 21% during the current six month period.

~~See~~Three ~~accompanying~~months ~~notes~~ended June 30, 2010 as compared to ~~financial~~three ~~statements.~~months ended June 30, 2009

-The moderate 7% increase in 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 34%, which was substantially offset by the production volume decrease of 20%. Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $5.44 for the current year quarter compared to $4-.07 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 refraced. Subsequent to a successful refracturing, 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 on PDC’s ability to market the Partnership’s production effectively. Natural gas and oil prices are among the most volatile of all commodity prices. This price volatility has a material impact on the Partnership’s financial results. Natural gas and oil prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality and availability of sufficient pipeline capacity. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply 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 at which PDC 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 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 the last year and is lower than historical variances. This negative differential between NYMEX and CIG averaged $1.13 and $1.38 for the three and six months ended June 30, 2009, respectively, and narrowed to an average of $0.48 and $0.32 for the three and six months ended June 30, 2010, respectively.

- 15 -

Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Notes~~Commodity toPrice ~~Financial Statements~~Risk Management, Net

~~(Unaudited)~~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. 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.

~~1. Accounting Policies~~The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain (loss), net.

The accompanying condensed interim financial statements and related disclosures are unaudited and have been prepared pursuant to U.S. generally accepted accounting principles for interim financial statements and the rules and regulations of the Securities and Exchange Commission (the Commission). As permitted by these regulations, certain information and footnote disclosures that would typically be required in annual financial statements have been condensed or omitted. However, management believes that these statements reflect all the normal recurring adjustments necessary for a fair presentation, in all material respects, of the results of operations for the periods presented, so that these interim financial statements are not misleading. These condensed financial statements should be read in conjunction with the financial statements and notes thereto included in the PDC 2003-A Limited Partnership's (the Partnership) Annual Report on Form 10-K for the year ended December 31, 2004.

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Commodity price risk management gain (loss), net
Realized gain
Oil	$	13,263		$	30,020		$	25,672		$	75,583
Natural Gas		—			62,135			57,518			154,793
Total realized gain, net		13,263			92,155			83,190			230,376

Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(9,094	)		(101,810	)		(49,078	)		(191,499	)
Unrealized gain (loss) for the period		61,934			(137,976	)		201,111			(190,516	)
Total unrealized gain (loss), net		52,840			(239,786	)		152,033			(382,015	)
Commodity price risk management gain (loss), net	$	66,103		$	(147,631	)	$	235,223		$	(151,639	)

~~2. Use of~~Six ~~Estimates~~months ended June 30, 2010 as compared to six months ended June 30, 2009

~~To prepare~~The ~~financial~~realized ~~statements~~derivative ingains ~~accordance~~for ~~with~~the ~~generally~~2010 ~~accepted~~six ~~accounting principles,~~month ~~the~~period ~~Partnership's~~were ~~management~~$0.1 ismillion ~~required~~as toa ~~make~~result ~~estimates~~of lower natural gas and ~~assumptions~~ ~~that~~oil ~~affect~~spot prices at settlement compared to the ~~reported~~respective ~~amounts~~strike ofprice. Unrealized ~~assets~~gains ~~and~~for ~~liabilities,~~the ~~and disclosure~~2010 ofsix ~~contingent~~month ~~assets~~period ~~and~~were ~~liabilities~~due atprimarily ~~the~~to ~~date~~a ofdownward shift in the ~~financial statements,~~natural gas and ~~reported~~oil ~~amounts~~forward ofcurves. Unrealized ~~revenues~~gains ~~and~~on ~~expenses~~the ~~incurred~~Partnership’s ~~during~~commodity ~~the reporting~~positions ~~period. Actual~~for ~~results~~the ~~could~~2010 ~~differ~~six ~~from~~month ~~those~~period ~~estimates~~were $0.2 million.

3For the 2009 six month period, the Partnership realized derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices. ~~Oil~~ Unrealized losses for the period were primarily related to oil swaps, as the forward strip price of oil rebounded during the period, and ~~Gas~~the ~~Properties~~basis position, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

~~The~~Three ~~Partnership follows~~months ~~the~~ended ~~successful~~June ~~efforts method of accounting for the cost of exploring for and developing oil and gas reserves. Under this method~~30, ~~costs~~2010 ~~of development~~as ~~wells,~~compared ~~including equipment and intangible drilling costs related~~ to ~~both~~ ~~producing~~three ~~wells~~months ~~and~~ended ~~developmental~~June ~~dry holes~~30, and successful exploratory wells are capitalized and amortized on an annual basis to operations by the units-of-production method using estimated proved developed reserves determined at year end by Petroleum Development Corporation's (the Managing General Partner's) petroleum engineers. If a determination is made that an exploratory well has not discovered economically producible reserves, then its costs are expensed as dry hole cost. 2009

The ~~Partnership assesses~~realized ~~impairment~~derivative ofgains ~~capitalized~~for ~~costs~~the of2010 ~~proved~~second ~~oil~~quarter ~~and~~on ~~gas~~the ~~properties~~Partnership’s ~~by comparing~~commodity ~~net~~positions ~~capitalized~~are ~~costs~~the toresult ~~undiscounted~~of ~~future~~lower ~~net~~natural ~~cash~~gas ~~flows~~and onoil ~~a field-by-field~~spot ~~basis~~prices ~~using~~at ~~expected~~settlement ~~prices. Prices~~compared ~~utilized~~to inthe ~~each~~respective ~~year's calculation~~strike ~~for~~price. For ~~measurement~~the ~~purposes~~2010 ~~and~~second ~~expected~~quarter, ~~costs~~the ~~are~~unrealized ~~held~~gains ~~constant throughout~~of ~~the~~$0.1 ~~estimated~~million ~~life~~were ofprimarily related to the ~~properties. If~~Partnership’s ~~net~~commodity ~~capitalized~~positions, ~~cost exceeds~~as ~~undiscounted~~the ~~future~~forward ~~net~~strip ~~cash~~price ~~flow,~~shifted downward during the ~~measurement~~quarter, ofand ~~impairment~~the ~~is based~~Partnership’s onbasis ~~estimated~~position ~~fair~~due ~~value~~to ~~which~~the ~~would~~widening ~~consider~~of ~~future~~the ~~discounted~~NYMEX-CIG ~~cash flows~~basis differential.

4For the 2009 second quarter, the Partnership realized derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices. ~~Revenue~~ Unrealized ~~Recognition~~losses for the period were primarily related to oil swaps, as the forward strip price of oil rebounded during the period, and the basis position, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

~~Sales~~- of16 natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month to three years. Virtually all of the Managing General Partner's contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.-

~~-5-~~Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Notes~~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 a basis swap on a portion of the Partnership’s natural gas and oil production. See Note 5, Derivative Financial ~~Statements~~ 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.

~~(Unaudited)~~The following table presents the Partnership’s derivative positions in effect as of June 30, 2010.

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

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
			Weighted Average				Quantity		Weighted Average				Weighted Average			Fair Value at
Commodity/	Quantity		Contract Price				(Gas-Mmbtu(1)		Contract		Quantity		Contract			June 30,
Index	(Gas-Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Price		(Gas-Mmbtu(1))		Price			2010(2)

Natural Gas
CIG
10/01 - 12/31/2010		5,276	$	4.75	$	9.45		—	$	—		—	$	—		$	3,220
01/01 - 03/31/2011		7,914		4.75		9.45		—		—		—		—			3,944

NYMEX
07/01 - 09/30/2010		—		—		—		16,776		5.56		17,558		(1.88	)		(5,295	)
10/01 - 12/31/2010		1,670		5.75		8.30		10,071		6.13		12,028		(1.88	)		(448	)
01/01 - 03/31/2011		2,275		5.75		8.30		6,128		6.83		8,403		(1.88	)		(822	)
04/01 - 06/30/2011		—		—		—		16,354		6.78		16,354		(1.88	)		5,824
07/01 - 12/31/2011		—		—		—		32,114		6.76		32,114		(1.88	)		516
2012-2013		3,626		6.00		8.27		113,415		7.05		117,039		(1.88	)		(4,604	)
Total Natural Gas		20,761						194,858				203,496					2,335

Oil
NYMEX
07/01 - 09/30/2010		—		—		—		896		92.96		—		—			14,818
10/01 - 12/31/2010		—		—		—		896		92.96		—		—			13,622
01/01 - 03/31/2011		—		—		—		447		70.75		—		—			(3,282	)
04/01 - 06/30/2011		—		—		—		456		70.75		—		—			(3,714	)
07/01 - 12/31/2011		—		—		—		939		70.75		—		—			(8,217	)
Total Oil		—						3,634				—					13,227

Total Natural Gas and Oil																$	15,562

~~Sales~~(1) ofA ~~oil~~standard ~~are~~unit ~~recognized when persuasive evidence~~ of ameasure ~~sales~~for ~~arrangement~~natural ~~exists,~~gas ~~the~~(one ~~oil~~MMbtu isequals ~~verified~~one ~~as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable~~Mcf). The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production. The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

~~5. Derivative Financial~~(2) ~~Instruments~~Approximately 15% 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.

~~The~~Natural Managing General Partner utilizes commodity based derivative instruments as hedges to manage a portion of the Partnership's exposure to price volatility stemming from natural gas and oil production. These instruments consist of CIG (Colorado Interstate Gas ~~Index) based contracts for Colorado production,~~ and ~~NYMEX~~Oil ~~(New~~Production York Mercantile Exchange) traded oil futures and option contracts for Colorado oil production. The costless collars and option contracts hedge committed and anticipated oil and natural gas sales generally forecasted to occur within a 24 month period. The Partnership does not hold or issue derivatives for trading or speculative purposes. Costs

~~All~~Generally, ~~derivatives~~natural ~~are recognized~~gas onand ~~the~~oil ~~Partnership's~~production ~~balance~~costs ~~sheet~~vary atwith ~~their~~changes ~~fair~~in ~~value.~~total Onnatural ~~the~~gas ~~date the~~and ~~derivative~~oil ~~contract~~sales isand ~~entered~~production ~~into,~~volumes. Production taxes are estimates by the Managing General Partner ~~designates~~ ~~the~~based ~~derivative~~on astax arates ~~hedge~~determined ofusing apublished ~~forecasted~~information. These ~~transaction~~estimates ~~(future~~are ~~production and~~subject ~~sales~~to ofrevision ~~oil~~based ~~and~~on ~~gas)~~actual ~~("cash~~amounts ~~flow"~~determined ~~hedge),~~during orfuture afilings ~~non-hedging~~by ~~derivative.~~the ~~The~~ Managing General Partner ~~formally~~with ~~documents~~the ~~all~~taxing ~~relationships~~authorities. Production ~~between~~taxes ~~hedging instruments~~vary ~~and~~directly ~~hedged~~with ~~items,~~total asnatural ~~well~~gas asand ~~its~~oil ~~risk-management~~sales. Transportation ~~objective~~costs ~~and strategy~~vary ~~for~~directly ~~undertaking~~with ~~various~~production ~~hedge transactions~~volumes. Fixed ~~This~~monthly ~~process~~well ~~includes linking~~operating ~~all~~costs ~~derivatives~~increase ~~that~~on ~~are~~a ~~designated~~per asunit ~~cash-flow~~basis ~~hedges~~as toproduction ~~specific firm~~decreases ~~commitments.~~per ~~The~~the ~~Managing~~historical ~~General~~decline ~~Partner~~curve. In ~~also formally assesses~~addition, ~~both~~general ~~at the~~oil ~~hedge's~~field ~~inception~~services and onall another ~~ongoing~~costs ~~basis,~~vary ~~whether~~and ~~the~~can ~~derivatives~~fluctuate ~~that~~based ~~are used~~on inservices ~~hedging~~required ~~transactions~~but are ~~highly~~expected ~~effective~~to inincrease ~~offsetting~~as ~~changes~~wells inage ~~cash flows~~and ofrequire ~~hedged~~more ~~items. When~~extensive itrepair isand ~~determined~~maintenance. These ~~that~~costs ainclude ~~derivative~~water ishauling ~~not~~and ~~highly effective~~disposal, asequipment arepairs ~~hedge~~and ormaintenance, ~~that~~snow ~~it has ceased to be a highly effective hedge~~removal, ~~the Partnership~~environmental ~~discontinues~~compliance ~~hedge~~and ~~accounting~~remediation ~~prospectively.~~and Noservice ~~hedging~~rig ~~activities were discontinued during 2005 or 2004~~workovers.

~~Changes~~Six inmonths ~~fair value~~ended ofJune ~~a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in accumulated other comprehensive income~~30, ~~until~~2010 earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Partnership discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is designated as acompared ~~hedging~~to ~~instrument,~~six ~~because~~months itended isJune ~~probable that a forecasted transaction will not occur~~30, ~~or the Partnership determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will be discontinued.~~2009

ByFor ~~using~~the ~~derivative~~six ~~financial~~months ~~instruments to~~ended ~~hedge~~June ~~exposures~~30, 2010 compared to ~~changes~~the same period in ~~commodity~~2009, ~~prices~~natural gas and oil production, ~~the~~on ~~Managing~~an ~~General~~energy ~~Partner exposes~~equivalency-basis, ~~the~~decreased ~~Partnership~~19%, due to ~~credit~~normal ~~risk.~~production ~~Credit~~declines ~~risk~~for isthis stage in the ~~failure~~wells’ ofproduction ~~the counterparty~~life cycle in addition to ~~perform~~production ~~under~~reductions ~~the~~that ~~terms~~resulted offrom ~~the~~well ~~derivative~~equipment ~~contract~~problems at two Partnership wells. Production ~~When~~and ~~the fair~~operating ~~value~~costs ofdeclined aslightly ~~derivative~~in ~~contract~~terms isof ~~positive~~amount, but remained substantially the ~~counterparty~~same ~~owes~~in cost per Mcfe for the ~~Partnership,~~ ~~which~~2010 ~~creates~~and ~~credit~~2009 ~~risk~~six month period. Production ~~The~~and ~~Managing~~operating ~~General~~costs ~~Partner~~per ~~minimizes~~ Mcfe were $1.88 for the ~~credit~~six ~~risk~~months inended ~~derivative~~June ~~instruments~~30 byof ~~entering~~2010 ~~into~~compared ~~transactions~~to ~~with high-quality~~$1.85 ~~counterparties~~for the comparable period in 2009.

-6 17 -

Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Notes~~Three months ended June 30, 2010 as compared to ~~Financial Statements~~three months ended June 30, 2009

~~(Unaudited)~~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 20%, primarily as a result of the Partnership wells’ reduced performance due to the reasons noted above, in addition to second quarter operational constraints at some Wattenberg Field wells. Production and operating costs were substantially the same at approximately $65,000 for the 2010 and 2009 quarter. Production and operating costs per Mcfe were $2.02 and $1.83 for the quarter ended June 30, 2010 and 2009, respectively. The production cost per Mcfe increase was due to higher production taxes as a result of higher commodity valuations and higher well operations costs as a result of the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement.

~~Item 2. Management's~~Depreciation, ~~Discussion~~Depletion and ~~Analysis of Financial Condition and Results of Operations~~Amortization

~~Liquidity~~ DD&A expense related to natural gas and ~~Capital~~oil ~~Resources~~properties is directly related to production volumes for the period. For the quarter ended June 30, 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, 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 ~~Partnership~~months ~~was~~ended ~~funded~~June ~~on April~~ 30, ~~2003~~2010 ~~with~~as ~~initial~~compared Limited and Additional General Partner contributions of $8,483,045 (424.15 units) and the Managing General Partner's cash contribution of $1,845,062 in accordance with the Limited Partnership Agreement. After payment of syndication costs of $890,720 and a one-time management fee to ~~the~~six ~~Managing General~~months ~~Partner~~ended ofJune ~~$212~~30,~~076~~ ~~the Partnership had available cash of $9,225,311 for Partnership activities.~~ 2009

The DD&A expense rate per Mcfe decreased to $3.25 for the 2010 six month period, compared to $5.01 during the same period in 2009. The decrease in the per Mcfe rates for the 2010 period compared to the 2009 period is due to the changing production mix between the Partnership ~~began~~’s ~~exploration~~Wattenberg and ~~development~~Grand ~~activities~~Valley ~~subsequent~~Fields, which have significantly different DD&A rates, in addition to the ~~funding~~effect of the upward revision in the Partnership’s proved developed producing natural gas and ~~completed~~oil ~~well~~reserves ~~drilling~~particularly ~~activities~~in bythe ~~December~~Wattenberg 31Field, ~~2003~~as calculated by the respective methodologies described above. ~~Twenty-five wells~~ The ~~have~~decreased ~~been~~DD&A ~~drilled~~expense rate, ~~all~~combined with the effect of ~~which~~the ~~have~~production ~~been~~declines ~~completed~~noted asin ~~producing~~previous ~~wells~~sections, resulted in a decreased DD&A expense of approximately $0. No2 ~~additional~~million ~~wells~~for ~~will~~the be2010 ~~drilled~~six month period compared to the same 2009 period.

~~The Partnership~~- ~~had~~18 ~~working capital at June 30, 2005 of $287,739.~~-

Operations are expected to be conducted with available funds and revenues generated from oil and gas activities. Under the Limited Partnership Agreement, the Partnership is not permitted to borrow funds.Index

~~Results of~~PDC ~~Operations~~2003-A LIMITED PARTNERSHIP

~~Three~~(A ~~months~~West ~~ended~~Virginia ~~June~~Limited ~~30, 2005 compared with June 30, 2004~~Partnership)

~~Oil and~~Three ~~gas sales for the three~~ months ended June 30, ~~2005~~2010 ~~were~~as ~~$493,765~~ compared to ~~$674,482 for the~~ three months ended June 30, 2004, a decrease of $180,717 or 26.8%. The volume of natural gas sold for the three months ended June 30, 2005, was 47,429 Mcf at an average sales price of $5.81 per Mcf compared to 96,461 Mcf at an average price of $4.56 per Mcf for the three months ended June 30, 2004. The volume of oil sold for the three months ended June 30, 2005 was 4,617 barrels at an average sales price of $47.21 compared to 6,912 barrels at an average price of $33.92 for the three months ended June 30, 2004. The lifting cost for the three months ended June 30, 2005 was $1.12 per Mcfe compared to $0.80 per Mcfe for the three months ended June 30, 2004. This increase is partially attributed to the increase in severance and property taxes along with costs associated with workovers. The fixed costs of operations and well maintenance are allocated to lower production volumes, therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization for the three months ended June 30, 2005 was $159,787 compared to $257,075 for the three months ended June 30, 2004. The Partnership experienced a net income of $250,313 and $306,914 and distributed $418,052 and $708,013 to the partners for the three months ended June 30, 2005 and 2004, respectively.2009

~~Six Months~~The ~~ended~~DD&A ~~June~~expense 30rate per Mcfe decreased to $3.24 for the 2010 second quarter, ~~2005~~compared to $5.12 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 annual reserve estimate revisions and change in field production mix, noted above. The lower DD&A expense rate, combined with ~~June~~the 30effect of the production declines noted in previous sections, ~~2004~~resulted in the DD&A expense reduction of $0.1 million for the 2010 second quarter compared to the same 2009 quarter.

~~Oil and~~Capital ~~gas~~Resources sales for the six months ended June 30, 2005 were $970,275 compared to $1,363,873 for the six months ended June 30, 2004, a decrease of $393,598 or 28.9%. The volume of natural gas sold for the six months ended June 30, 2005, was 104,154 Mcf at an average sales price of $5.67 per Mcf compared to 191,890 Mcf at an average price of $4.45 per Mcf for the six months ended June 30, 2004. The volume of oil sold for the six months ended June 30, 2005 was 8,167 barrels at an average sales price of $46.42 compared to 15,200 barrels at an average price of $33.57 for the six months ended June 30, 2004. The lifting cost for the six months ended June 30, 2005 was $1.07 per Mcfe compared to $.74 per Mcfe for the six months ended June 30, 2004. The increase is partially attributed to the increase in severance and property taxes along with costs associated with workovers. The fixed costs of operations and well maintenance are allocated to lower production volumes therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization for the six months ended June 30, 2005 was $325,728 compared to $527,576 for the six months ended June 30, 2004. The Partnership experienced a net income of $481,244 and $626,369 and distributed $907,168 and $1,496,960 to the partners for the six months ended June 30, 2005 and 2004, respectively.Liquidity

~~-7-~~The Partnership’s primary sources of cash for both the three and the six months ended June 30, 2010 were from funds provided 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 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 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 June 30, 2010, the Partnership had natural gas and oil derivative positions in place covering 72% of the expected natural gas production and 64% of expected oil production for the remainder of 2010, at an average price of $3.97 per Mcf and $92.96 per Bbl, respectively. The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2009 comparative period, which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010. 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.

~~PDC~~The ~~2003-A~~Partnership’s ~~LIMITED PARTNERSHIP~~future operations are expected to be conducted with available funds and revenues generated from natural gas and oil production activities and commodity gains, if any. 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 lives of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas and oil production and, in the absence of significant price increases or successful refracturings, 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 Managing General Partner and Investor Partners through the remainder of 2010 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the Well Refracturing Plan activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Well Refracturing Plan.

(A- ~~West~~19 ~~Virginia Limited Partnership)~~-

~~Notes to Financial Statements~~Index

~~(Unaudited)~~PDC 2003-A LIMITED PARTNERSHIP

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

~~Critical Accounting~~Working ~~Policies~~Capital

~~Certain~~The ~~accounting policies are very important to the portrayal of the~~ Partnership's ~~financial~~working ~~condition~~capital ~~and~~remained ~~results~~substantially ~~of operations~~unchanged ~~and~~at ~~require management's most subjective or complex judgments~~$0. ~~In applying~~1 ~~those~~million ~~policies,~~as ~~our management uses its judgment to determine the appropriate assumptions to be used in the determination~~ of ~~certain~~June ~~estimates. Those estimates are based on our historical experience~~30, ~~our~~2010 ~~observance~~and ~~of trends~~December ~~in the industry~~31, ~~and information available from other outside sources~~2009, as ~~appropriate~~respectively. ~~The Partnership's critical accounting policies and estimates are as follows:~~

~~Revenue~~Working ~~Recognition. Sales~~capital, ofprimarily ~~natural~~cash ~~gas~~and ~~are~~cash ~~recognized when~~equivalents, ~~natural~~is ~~gas~~expected ~~has been delivered~~ to aincrease ~~custody~~during ~~transfer~~early ~~point,~~2011 ~~persuasive evidence~~due ofto ~~a sales arrangement exists,~~ the ~~rights~~Partnership’s ~~and~~anticipated ~~responsibility~~withholding of ~~ownership~~ ~~pass~~cash tofrom the ~~purchaser~~Managing ~~upon~~General ~~delivery,~~Partner ~~collection~~and ofInvestor ~~revenue~~Partners, ~~from~~on ~~the sale~~a ispro-rata ~~reasonably~~basis, ~~assured~~for ~~and~~ the ~~sales~~initial ~~price~~Wattenberg isField ~~fixed~~well orrefracturing ~~determinable~~activities. ~~Natural~~ This ~~gas~~withholding is ~~sold~~expected byto ~~the~~begin ~~Managing~~in ~~General~~the ~~Partner~~fourth ~~under~~quarter ~~contracts~~of ~~with~~2010. Cash ~~terms ranging~~will ~~from~~begin ~~one month~~ to ~~three~~decrease ~~years. Virtually~~as ~~all of~~ the ~~Managing~~funds ~~General Partner's contracts pricing provisions~~ are ~~tied~~utilized toin apayment ~~market~~of ~~index,~~the ~~with~~completed ~~certain adjustments~~refracturing ~~based on~~activities, ~~among~~currently ~~other~~planned ~~factors, whether a well delivers~~ to ~~a gathering~~occur orduring ~~transmission~~2011. ~~line,~~Funding ~~quality~~for ofthe ~~natural~~Well ~~gas~~Refracturing ~~and~~Plan ~~prevailing~~will ~~supply and~~be ~~demand~~provided ~~conditions,~~by ~~so that~~ the ~~price~~withholding of ~~the~~distributable ~~natural~~cash ~~gas~~flows ~~fluctuates~~from ~~to remain~~the ~~competitive~~Managing ~~with~~General ~~other~~Partner ~~available~~and ~~natural~~Investor ~~gas~~Partners ~~supplies. As~~on a ~~result,~~pro-rata ~~the Partnership's~~basis. ~~revenues~~Working ~~from~~capital ~~the~~is ~~sale~~expected ofto ~~natural~~similarly ~~gas~~fluctuate ~~will~~by ~~suffer~~increasing ifduring ~~market prices~~periods ~~decline~~of ~~and~~Well ~~benefit~~Refracturing ifPlan ~~they~~funding ~~increase.~~and ~~The~~by ~~Partnership~~decreasing ~~believes~~during ~~that~~periods ~~the pricing~~when ~~provisions~~payments ~~of its natural gas contracts~~ are ~~customary~~made infor ~~the~~completed ~~industry~~well refracturing.

~~The Managing~~Cash ~~General Partner currently uses the "Net-Back" method of accounting for transportation arrangements~~Flows

~~of natural~~Cash ~~gas~~Flows ~~sales. The~~From ~~Managing~~Investing General Partner sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner's customers and reflected in the wellhead price.Activities

~~Sales of~~The ~~oil~~Partnership, ~~are~~from ~~recognized~~time-to-time, ~~when~~invests ~~persuasive~~in ~~evidence~~additional ofequipment awhich ~~sales~~supports ~~arrangement exists~~treatment, ~~the~~ ~~oil~~delivery ~~is verified as produced~~ and ismeasurement ~~delivered in a stock tank, collection~~ of ~~revenue~~ ~~from~~natural ~~the~~gas ~~sale is reasonably assured~~ and ~~the~~oil ~~sales~~or ~~price~~environmental ~~is determinable~~protection. ~~The~~ These ~~Partnership~~amounts istotaled ~~currently~~approximately ~~able~~$1,000 ~~to sell all the oil that it can produce under existing sales contracts with petroleum refiners~~ and ~~marketers. The~~ ~~Partnership~~$24,000 ~~does~~for ~~not refine any of its oil production. The Partnership's crude oil production is sold to purchasers at or near~~ the ~~Partnership's~~ ~~wells~~six ~~under~~months ~~short-term~~ended ~~purchase~~June ~~contracts~~30, at2010 ~~prices~~ and ~~in accordance~~2009, ~~with arrangements that are customary in the oil industry~~respectively.

~~Impairment~~Cash ofFlows ~~Long-Lived~~From ~~Assets~~Financing The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.Activities

~~-8-~~The Partnership initiated monthly cash distributions to investors in November 2003 and has distributed $9.3 million through June 30, 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.

PDC 2003-A LIMITED PARTNERSHIP


Three months ended June 30,	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
2010	$	33,697	$	134,785	$	168,482

2009	$	57,262	$	229,046	$	286,308


Six months ended June 30,	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions

2010	$	77,381	$	309,520	$	386,901

2009	$	103,408	$	413,633	$	517,041

(A- ~~West~~20 ~~Virginia Limited Partnership)~~-

~~Notes to Financial Statements~~Index

~~(Unaudited)~~PDC 2003-A LIMITED PARTNERSHIP

~~Oil~~(A ~~and~~West ~~Gas~~Virginia ~~Properties~~Limited Partnership)

~~Exploration~~Cash ~~and development~~Flows ~~costs~~From ~~are~~Operating ~~accounted for by the successful efforts method.~~Activities

~~Property~~Net ~~acquisition~~cash ~~costs~~provided ~~are~~by ~~capitalized~~operating ~~when incurred. Geological~~activities ~~and~~was ~~geophysical~~$0.4 ~~costs~~million ~~and~~for ~~delay~~the ~~rentals~~six ~~are~~months ~~expensed~~ended ~~as incurred. The~~June ~~costs~~30, of2010, ~~drilling~~compared ~~exploratory~~to ~~wells~~approximately ~~are~~$0.6 ~~capitalized~~million ~~pending determination~~for ~~of whether~~ the ~~wells~~comparable ~~have~~period ~~discovered~~in ~~economically producible reserves~~2009. If The ~~reserves~~approximately ~~are~~$0.2 ~~not~~million ~~discovered,~~decrease ~~such~~in ~~costs~~cash ~~are~~provided ~~expensed~~by asoperating ~~dry holes. Development~~activities ~~costs,~~was ~~including~~due ~~equipment~~primarily ~~and intangible drilling costs related~~ to ~~both~~the ~~producing wells and developmental dry holes are capitalized.~~following:

~~Unproved~~● ~~properties~~An ~~and~~increase ~~leases~~in ~~are~~natural ~~written-off~~gas toand ~~expense when~~oil itsales isreceipts ~~determined~~of ~~that~~$0.1 ~~they~~million, ~~will~~or ~~expire to be abandoned.~~36%;

~~Costs~~● ofA ~~proved~~decrease ~~properties,~~in ~~including~~commodity ~~leasehold acquisitions,~~price ~~exploration~~risk ~~and~~management ~~development~~realized ~~costs~~gains ~~and~~receipts ~~equipment,~~of ~~are~~$0.1 ~~depreciated and~~million, ~~depleted~~or by47%; ~~the~~and ~~unit-of-production~~an ~~method~~increase ~~based~~in ondirect ~~estimated~~costs ~~proved developed~~– ~~oil~~general and ~~gas~~administrative ~~reserves~~of $0.1 million; and

~~Upon~~● ~~sale~~A ordecrease ~~retirement~~in ofDue ~~complete~~to ~~fields~~Managing ofGeneral ~~depreciable or depletable property~~Partner-other, ~~the book value thereof~~net, ~~less~~receipts ~~proceeds~~of orapproximately ~~salvage~~$0.1 ~~value~~million, is ~~credited~~excluding ornatural ~~charged~~gas toand ~~income. Upon~~oil ~~sale~~sales ofreceived afrom ~~partial~~third ~~unit~~parties ofand ~~property,~~realized ~~the proceeds~~derivative ~~are credited to accumulated depreciation and depletion~~gains.

~~Recently Issued~~Commitments ~~Accounting~~and ~~Pronouncements~~Contingencies

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

On Recent ~~March 30, 2005, the FASB issued FASB Interpretation No. 47, "~~Accounting for Conditional Asset Retirement Obligations" (FIN No. 47). This interpretation clarifies that the term "conditional asset retirement obligation" as used in Statement No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 will be effective for the Partnership at the end of the fiscal year ended December 31, 2005. The Partnership has not yet determined the final impact on the Partnership's financial position or results of operations of the application of FIN No. 47, however the Partnership does expect to record an unfavorable cumulative effect of change in accounting principle within the statement of operations before year end. Such effect may be material to the financial statements.Standards

~~-9-~~See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements, included in this report.

~~PDC~~Critical ~~2003-A~~Accounting ~~LIMITED PARTNERSHIP~~Policies and Estimates

(AThe ~~West~~preparation ~~Virginia Limited~~of ~~Partnership)~~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.

~~Notes~~There have been no other significant changes to ~~Financial Statements~~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.

~~(Unaudited)~~Off-Balance Sheet Arrangements

~~Disclosure Regarding~~Currently, ~~Forward~~the ~~Looking~~Partnership ~~Statements~~does not have any off-balance sheet arrangements.

~~This Form 10~~-Q ~~contains~~21 ~~"forward~~-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are the Managing General Partner's estimate of the sufficiency of its existing capital sources, its ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Partnership has filed with the Securities and Exchange Commission. The Partnership undertakes no duty to update or revise these forward-looking statements.

When used in the Form 10-Q, the words, "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Management's Discussions and Analysis of Financial Condition and Results of Operations" and elsewhere in this Form 10-Q. Index

~~Item~~PDC ~~3. Quantitative~~2003-A ~~and~~LIMITED ~~Qualitative Disclosure About Market Risk~~PARTNERSHIP

~~Market-Sensitive~~(A ~~Instruments~~West ~~and~~Virginia ~~Risk~~Limited ~~Management~~Partnership)

~~The Partnership's~~Item ~~primary~~3. ~~market~~Quantitative ~~risk~~and ~~exposure~~Qualitative isDisclosures ~~commodity~~About ~~price~~Market ~~risk. This exposure is discussed in detail below:~~Risk

~~Commodity~~Not ~~Price Risk~~applicable.

~~The Managing~~Item ~~General Partner utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its oil and natural gas sales~~4. ~~These~~ ~~instruments~~Controls consist of CIG-based contracts traded by JP Morgan for Colorado production. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Managing General Partner will receive for the volume to which the hedge relates. As a result, while these hedging arrangements are structured to reduce Partnership's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Partnership might otherwise have received from price changes associated with the hedged commodity. The Partnership's policy prohibits the use of oil and ~~natural gas future and option contracts for speculative purposes.~~Procedures

The ~~following~~Partnership ~~tables~~has ~~summarize~~no ~~the~~direct ~~open~~management ~~futures~~or officers. The management, officers and ~~options~~ ~~contracts~~other ~~for~~employees ~~the~~that ~~Partnership~~provide asservices on behalf of ~~June~~the ~~30,~~Partnership ~~2005~~are ~~and~~employed ~~June~~by ~~30,~~the ~~2004~~Managing General Partner.

	Type	Quantity Gas-Mmbtu Oil-Barrels	Weighted Average Price	Total Contract Amount	Fair Market Value
Total Contracts as of June 30, 2005
Natural Gas	Floors	90,089	$ 4.27	-	$ 1,957
Natural Gas	Ceilings	45,044	$ 6.83	-	$ (34,764)
Oil	Floors	4,163	$32.30	$134,461	$ 18
Oil	Ceilings	2,081	$40.00	$ 83,258	$ (37,891)

(a) Evaluation of Disclosure Controls and Procedures

As of June 30, 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-1015(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.

~~PDC~~Based ~~2003-A~~on ~~LIMITED PARTNERSHIP~~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 June 30, 2010.

(Ab) ~~West~~Changes ~~Virginia Limited~~in ~~Partnership)~~Internal Control over Financial Reporting

~~Notes~~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 June 30, 2010, that have materially affected or are reasonably likely to ~~Financial Statements~~materially affect the Partnership’s internal control over financial reporting.

~~(Unaudited)~~- 22 -

Contracts maturing in 12 months following June 30, 2005
Natural Gas	Floors	72,596	$ 4.22	-	$ 1,247
Natural Gas	Ceilings	36,298	$ 6.72	-	$ (30,123)
Oil	Floors	4,163	$32.30	$134,461	$ 18
Oil	Ceilings	2,081	$40.00	$ 83,258	$ (37,891)
Prior Year Total Contracts as of June 30, 2004
Natural Gas	Floors	254,781	$ 3.90	-	-
Natural Gas	Ceilings	127,390	$ 5.01	-	57,401)
Oil	Sales	6,974	$31.63	$220,580	(38,367)

Index

~~The~~PDC ~~maximum~~2003-A ~~term~~LIMITED ~~over which the Partnership is hedging exposure to the variability of cash flows for commodity price risk is 16 months.~~ PARTNERSHIP

~~Disclosure~~(A ofWest ~~Limitations~~Virginia Limited Partnership)

AsPART ~~the~~II ~~information~~– ~~above~~OTHER incorporates only those exposures that exist at June 30, 2005, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.INFORMATION

Item 41. ~~Controls~~ ~~and~~Legal ~~Procedures~~Proceedings

~~Under~~Information ~~the~~regarding ~~supervision and with~~ the ~~participation of the Managing General Partner'~~Registrant’s ~~management,~~legal ~~including~~proceedings ~~the~~can Managing General Partner's Chief Executive Officer and Chief Financial Officer, the Managing General Partner has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of this fiscal quarter, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be ~~disclosed~~found in ~~reports filed~~Note ~~or submitted under the Securities Exchange Act is recorded~~6, ~~processed, summarized,~~Commitments and ~~reported~~Contingencies, ~~within the time periods specified in the Commission's rules and forms, and is accumulated and communicated~~ to ~~management, including~~ the ~~Managing General Partner'~~Partnership’s ~~Chief~~accompanying ~~Executive~~unaudited ~~Officer~~condensed ~~and Chief Financial Officer, as appropriate to allow for timely disclosure. There have been no significant changes in our internal control over~~ financial reporting or in other factors that have materially affected or are reasonably likely to materially affect these controls that occurred during the Partnership's last fiscal quarter and subsequent to the date of their evaluationstatements.

~~-11-~~Item 1A. Risk Factors

~~CONFORMED~~Not ~~COPY~~applicable.

~~PART~~Item II2. -Unregistered ~~OTHER INFORMATION~~Sales of Equity Securities and Use of Proceeds

~~Item~~Unit ~~1 Legal Proceedings~~Repurchase Program: Beginning November 2006, 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 units repurchased during the three months ended June 30, 2010.

~~None~~Item 3. Defaults Upon Senior Securities

~~Item~~Not ~~6 Exhibits~~ applicable.

Exhibit Name	Exhibit Number
Rule 13a-14(a)/15d-14(a) Certifications by Chief Executive Officer	31
Rule 13a-14(a)/15d-14(a) Certification by Chief Financial Officer	31
Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Limited Partnership	32

Item 4.

[Removed and Reserved]

~~SIGNATURES~~Item 5. Other Information

~~Pursuant~~Not ~~to the requirements of the Securities Exchange Act of 1934 the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized~~applicable.

	PDC 2003-A Limited Partnership (Registrant) By its Managing General Partner Petroleum Development Corporation
Date: July 22, 2005	/s/ Steven R. Williams Steven R. Williams Chief Executive Officer
Date: July 22, 2005	/s/ Darwin L. Stump Darwin L. Stump Chief Financial Officer

- 23 -

~~-12-~~Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.

Exhibits

(a) Exhibit Index.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

3.1

Limited Partnership Agreement

10-K

000-50615

3.1

10/12/2010

3.2

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

10-K

000-50615

3.2

10/12/2010

10.1

Drilling and operating agreement between the Partnership and Petroleum Development Corporation (dba PDC Energy), as Managing General Partner.

10-K

000-50615

10.1

10/12/2010

31.1

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

31.2

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

32.1

Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

- 24 -

Index

PDC 2003-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 2003-A Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

December 15, 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

/s/ Richard W. McCullough	Chairman and Chief Executive Officer	December 15, 2010
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	December 15, 2010
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	December 15, 2010
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)

- 25 -

Filing Compare · PDC 2003-A LP