UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

OF 1934

For the quarterly period ended June 30, 2011

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-50615

PDC 2003-A Limited Partnership

(Exact name of registrant as specified in its charter)



	West Virginia		51-0452053
	(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

(303) 860-5800

(Registrant's telephone number, including area code)

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

Yes R No £

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 R No £

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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



	Large accelerated filer £		Accelerated filer £

	Non-accelerated filer £		Smaller reporting company R

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

As of June 30, 2011 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)

INDEX TO REPORT ON FORM 10-Q



PART I – FINANCIAL INFORMATION
		Page
	Special 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	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	25

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	26
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3.	Defaults Upon Senior Securities	26
Item 4.	[Removed and Reserved]	26
Item 5.	Other Information	26
Item 6.	Exhibits	27

	SIGNATURES	28

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2003-A Limited Partnership's (“Partnership” or the “Registrant”) business, financial condition and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. 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. These statements include: estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves; drilling plans; future cash flows and anticipated liquidity; anticipated capital expenditures; the adequacy of the Managing General Partner's casualty insurance coverage; the effectiveness of the Managing General Partner's derivative policies in achieving the Partnership's risk management objectives; and the Managing General Partner's strategies, plans and objectives.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the development, production and marketing of natural gas, NGLs and crude 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 and worldwide demand;


•	volatility of commodity prices for natural gas, NGLs and crude oil;


•	changes in estimates of proved reserves;


•	inaccuracy of reserve estimates and expected production rates;


•	declines in the value of the Partnership's natural gas and crude oil properties resulting in impairments;


•	the availability of Partnership future cash flows for investor distributions or funding of refracturing activities;


•	the timing and extent of the Partnership's success in further developing and producing the Partnership's reserves;


•	the Managing General Partner's ability to acquire drilling rig services, supplies and services at reasonable prices;


•	risks incidental to the refracturing and operation of natural gas and crude oil wells;


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


•	changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws;


•	the impact of environmental events, governmental responses to the events and the Managing General Partner's ability to insure adequately against such events;


•	the timing and receipt of necessary regulatory permits;


•	competition in the oil and gas industry;


•	the success of the Managing General Partner in marketing the Partnership's natural gas, NGLs and crude oil;


•	the effect of natural gas and crude oil derivative activities;


•	the cost of pending or future litigation;


•	the Managing General Partner's ability to retain or attract senior management and key technical employees; and


•	the success of strategic plans, expectations and objectives for future operations of the Managing General Partner.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership's annual report on Form 10-K for the year ended December 31, 2010 filed with the United States Securities and Exchange Commission (“SEC”) on March 30, 2011 (“2010 Form 10-K”) and the Partnership's other filings with the SEC for further information on risks and uncertainties that could affect the Partnership's business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. 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. All forward looking statements are qualified in their entirety by this cautionary statement.

-1-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PDC 2003-A Limited Partnership

Condensed Balance Sheets

(unaudited)



	June 30, 2011			December 31, 2010*
Assets

Current assets:
Cash and cash equivalents	$	10,228		$	10,221
Accounts receivable	42,542			68,082
Crude oil inventory	16,229			12,237
Due from Managing General Partner-derivatives	138,704			127,068
Total current assets	207,703			217,608

Natural gas and crude oil properties, successful efforts method, at cost	9,370,893			9,368,764
Less: Accumulated depreciation, depletion and amortization	(5,895,266		)	(5,722,912		)
Natural gas and crude oil properties, net	3,475,627			3,645,852

Due from Managing General Partner-derivatives	167,612			207,714
Other assets	29,279			25,895
Total noncurrent assets	3,672,518			3,879,461

Total Assets	$	3,880,221		$	4,097,069

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	6,261		$	14,120
Due to Managing General Partner-derivatives	117,781			119,159
Due to Managing General Partner-other, net	505,996			590,455
Total current liabilities	630,038			723,734

Due to Managing General Partner-derivatives	120,750			157,468
Asset retirement obligations	121,947			118,420
Total liabilities	872,735			999,622

Commitments and contingent liabilities

Partners' equity:
Managing General Partner	602,790			620,782
Limited Partners - 424.15 units issued and outstanding	2,404,696			2,476,665
Total Partners' equity	3,007,486			3,097,447

Total Liabilities and Partners' Equity	$	3,880,221		$	4,097,069

*Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2-

PDC 2003-A Limited Partnership

Condensed Statements of Operations

(unaudited)



	Three months ended June 30,					Six months ended June 30,
	2011			2010		2011			2010
Revenues:
Natural gas, NGLs and crude oil sales	$	152,088		$	166,053	$	299,387		$	383,668
Commodity price risk management gain, net	39,294			66,103		14,038			235,223
Total revenues	191,382			232,156		313,425			618,891

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	62,813			61,597		117,412			117,885
Direct costs - general and administrative	39,767			1,374		95,742			2,264
Depreciation, depletion and amortization	89,072			98,829		172,354			204,254
Accretion of asset retirement obligations	1,777			1,674		3,527			3,324
Total operating costs and expenses	193,429			163,474		389,035			327,727

Income (loss) from operations	(2,047		)	68,682		(75,610		)	291,164

Interest income	4			—		8			—

Net income (loss)	$	(2,043	)	$	68,682	$	(75,602	)	$	291,164

Net income (loss) allocated to partners	$	(2,043	)	$	68,682	$	(75,602	)	$	291,164
Less: Managing General Partner interest in net income (loss)	(408		)	13,737		(15,120		)	58,233
Net income (loss) allocated to Investor Partners	$	(1,635	)	$	54,945	$	(60,482	)	$	232,931

Net income (loss) per Investor Partner unit	$	(4	)	$	130	$	(143	)	$	549

Investor Partner units outstanding	424.15			424.15		424.15			424.15

See accompanying notes to unaudited condensed financial statements.

-3-

PDC 2003-A Limited Partnership

Condensed Statements of Cash Flows

(unaudited)



	Six months ended June 30,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	(75,602	)	$	291,164
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization	172,354			204,254
Accretion of asset retirement obligations	3,527			3,324
Unrealized gain on derivative transactions	(9,630		)	(152,033		)
Changes in operating assets and liabilities:
Decrease in accounts receivable	25,540			8,864
Increase in crude oil inventory	(3,992		)	(724		)
Increase in other assets	(3,384		)	(3,405		)
Decrease in accounts payable and accrued expenses	(7,859		)	(1,464		)
Increase (decrease) in Due to Managing General Partner - other, net	(84,459		)	29,921
Decrease in Due from Managing General Partner - other, net	—			8,289
Net cash provided by operating activities	16,495			388,190

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	(2,129		)	(1,337		)
Net cash used in investing activities	(2,129		)	(1,337		)

Cash flows from financing activities:
Distributions to Partners	(14,359		)	(386,901		)
Net cash used in financing activities	(14,359		)	(386,901		)

Net increase (decrease) in cash and cash equivalents	7			(48		)
Cash and cash equivalents, beginning of period	10,221			133
Cash and cash equivalents, end of period	10,228			85

See accompanying notes to unaudited condensed financial statements.

-4-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

Note 1−General and Basis of Presentation

PDC 2003-A Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations of the Partnership commenced upon closing of an offering for the sale of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of June 30, 2011, there were 430 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through June 30, 2011, the Managing General Partner has repurchased 20.3 units of Partnership interests from the Investor Partners at an average price of $8,227 per unit. As of June 30, 2011, the Managing General Partner owns 23.8% of the Partnership.

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership's wells are depleted or become uneconomical to produce, at which time they 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 (“SEC”). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the 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 2010 Form 10-K. The Partnership's accounting policies are described in the Notes to Financial Statements in the Partnership's 2010 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, 2011, and the cash flows for the same periods, are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to correct the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 4, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's natural gas and crude oil derivative instruments.

On June 20, 2011, the Partnership, PDC and its wholly-owned subsidiary, DP 2004 Merger Sub, LLC (“DP Merger Sub”), a Delaware limited liability company, entered into an agreement and plan of merger (the “Merger Agreement”), in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held, by Investor Partners of the Partnership, other than PDC and its affiliates (“non-affiliated investor partners”). Pending the outcome of the proposed Merger Agreement, the Managing General Partner suspended, as of April 7, 2011, the opportunity for an individual non-affiliated investor partner to request that PDC repurchase their respective limited partnership units. For more information on the proposed Merger Agreement, see Note 3, Transactions with Managing General Partner and Affiliates−Proposed Merger with PDC and DP 2004 Merger Sub, LLC, which follows.

-5-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board ("FASB") issued changes 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. These changes were effective for the Partnership's financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership's financial statements.

Recently Issued Accounting Standards

Fair Value Measurement

On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership's financial statements.

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 condensed balance sheets 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.

-6-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

The following table presents transactions with the Managing General Partner reflected in the condensed 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, 2011			December 31, 2010
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	58,267		$	33,561
Commodity price risk management, realized gain	1,548			18,247
Other ⁽¹⁾	(565,811		)	(642,263		)
Total Due to Managing General Partner-other, net	$	(505,996	)	$	(590,455	)


(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 the three and six months ended June 30, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.



	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
Well operations and maintenance	$	49,383	$	46,997	$	93,203	$	88,083
Gathering, compression and processing fees	4,979		5,161		8,983		10,907
Direct costs - general and administrative	39,767		1,374		95,742		2,264
Cash distributions ⁽¹⁾	1,824		39,524		3,414		90,762


(1)	Cash distributions include $294 and $542 during the three and six months ended June 30, 2011, respectively, and $5,827 and $13,381 during the three and six months ended June 30, 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

Proposed Merger with PDC and DP 2004 Merger Sub, LLC

On June 20, 2011, the Partnership, PDC and DP Merger Sub entered into the Merger Agreement, in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held by non-affiliated investor partners. Pursuant to the 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 the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub, the separate existence of the Partnership will terminate and the non-affiliated investor partners will have the right to receive cash payments in the aggregate amount of $3,281,281 or $8,125 per limited partnership unit, subject to any adjustments made to the merger consideration for certain increases in commodity prices between the date of signing the merger agreement and the filing of the definitive proxy statement, plus the sum of the amounts withheld, if any, from per unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership's Well Refracturing Plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity. The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership's future earnings or any further economic benefit.

-7-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

The Merger Agreement has been approved by PDC's Board of Directors (the “Board”); PDC, as sole member of the DP Merger Sub; and by the Special Committee formed by the Board, comprised of four directors of PDC who are not officers or employees of the Partnership or PDC and have no economic interest in the Partnership, to represent the interests of the non-affiliated investor partners holding limited partnership units.

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


•	should all parties agree by mutual consent to terminate the Merger Agreement;


•	by any party thereto, should the proposed merger not occur by December 15, 2011;


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


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


•	by the Special Committee, on behalf of the Partnership and prior to approval by non-affiliated investor partners, should the Special Committee believe it has received a superior offer that is more favorable to the non-affiliated investor partners; or


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

On June 23, 2011, the Partnership filed a preliminary proxy statement on Schedule 14A relating to the merger with the SEC. Although there is no assurance of the likelihood or timing of the merger transaction, upon clearance by the SEC, a definitive proxy statement will be mailed to the Partnership’s limited partners. Closing of the merger is conditioned on approval by a majority vote of non-affiliated investor partners on both proposals to (1) amend the limited partnership agreement to expressly provide non-affiliated investor partners the right to approve merger transactions and (2) approve the Merger Agreement, as described above. If approved by a majority vote of non-affiliated investor partners and after the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware, no additional filing or registration with, notification to, or authorization, consent or approval of, any governmental entity will be required in connection with the execution and delivery of the Merger Agreement by the Partnership, PDC or DP Merger Sub or the consummation by the Partnership, PDC or DP Merger Sub of the transactions contemplated thereby. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or any further economic benefit.

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

-8-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

Note 4−Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

Derivative Financial Instruments. The Partnership measures the fair value of its derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets, both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The counterparties to the Partnership's derivative instruments are primarily financial institutions. The Managing General Partner validates the fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the 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. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

-9-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, both current and non-current portions, measured at fair value on a recurring basis.



	June 30, 2011								December 31, 2010 (a)
	Level 2 (b)			Level 3 (c)		Total			Level 2 (b)			Level 3 (c)		Total

Assets:
Commodity based derivatives	$	301,635		$	4,681	$	306,316		$	321,245		$	13,537	$	334,782
Total assets	301,635			4,681		306,316			321,245			13,537		334,782

Liabilities:
Commodity based derivatives	(23,663		)	—		(23,663		)	(40,635		)	—		(40,635		)
Basis protection derivative contracts	(214,868		)	—		(214,868		)	(235,992		)	—		(235,992		)
Total liabilities	(238,531		)	—		(238,531		)	(276,627		)	—		(276,627		)
Net asset	$	63,104		$	4,681	$	67,785		$	44,618		$	13,537	$	58,155

(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by approximately $321,000) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by approximately $277,000). The amounts presented reflect these reclassifications and conform to current period presentation.

(b) Includes the Partnership's fixed-price swaps and basis swaps.

The following table presents a reconciliation of the Partnership's Level 3 fair value measurements.



	Six months ended
	June 30, 2011			June 30, 2010 (1)
Fair value, net asset, beginning of period	$	13,537		$	26,312
Changes in fair value included in statement of operations line item:
Commodity price risk management, net	2,048			13,312
Settlements	(10,904		)	(26,288		)
Fair value, net asset, end of period	$	4,681		$	13,336

Change in unrealized gain (loss) relating to assets (liabilities) still held as of
June 30, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management, net	$	475		$	10,734

(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 decreasing the previously reported net liability at the beginning of the period by approximately $235,000). The amounts presented reflect these reclassifications and conform to current period presentation.

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

Non-Derivative Financial 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.

-10-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

Note 5−Derivative Financial Instruments

As of June 30, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 149,153 MMbtu of natural gas and 939 Bbl of crude oil.

The following table presents the location and fair value amounts of the Partnership's derivative instruments on the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.



			Fair Value
			June 30,		December 31,
Derivative instruments not designated as hedge⁽¹⁾:		Balance Sheet Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	138,704	$	127,068
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives	167,612		207,714
Total Derivative Assets			$	306,316	$	334,782

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	23,663	$	40,635
	Basis protection contracts	Due to Managing General Partner-derivatives	94,118		78,524
	Non Current
	Basis protection contracts	Due to Managing General Partner-derivatives	120,750		157,468
Total Derivative Liabilities			$	238,531	$	276,627

⁽¹⁾As of June 30, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.

-11-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

The following tables presents the impact of the Partnership's derivative instruments on the Partnership's accompanying condensed statements of operations.



	Three months ended June 30,
	2011								2010
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 For the Current Period		Total
Commodity price risk management gain, net
Realized gains (losses)	$	(284	)	$	914		$	630	$	9,094		$	4,169	$	13,263
Unrealized gains (losses)	284			38,380			38,664		(9,094		)	61,934		52,840
Total commodity price risk management gain, net	$	—		$	39,294		$	39,294	$	—		$	66,103	$	66,103

	Six months ended June 30,
	2011								2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains (losses)	$	8,301		$	(3,893	)	$	4,408	$	49,078		$	34,112	$	83,190
Unrealized gains (losses)	(8,301		)	17,931			9,630		(49,078		)	201,111		152,033
Total commodity price risk management gain, net	$	—		$	14,038		$	14,038	$	—		$	235,223	$	235,223

Concentration of Credit Risk. The Managing General Partner makes extensive use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner's credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership's derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.

-12-

PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2011

(unaudited)

Note 6−Commitments and Contingencies

Legal Proceedings

Neither the Partnership nor PDC, in its capacity as the Managing General Partner of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership's business, financial condition, results of operations or liquidity.

Environmental

Due to the nature of the natural gas and crude oil industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place 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. During the six months ended June 30, 2011, there were no new environmental remediation projects identified by the Managing General Partner for the Partnership. As of June 30, 2011 the Partnership has no accrued environmental liabilities. At December 31, 2010, the Partnership had accrued environmental remediation liabilities for one Partnership well in the amount of approximately $9,000, which is included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets. The Managing General Partner is not currently aware of any environmental claims existing as of June 30, 2011, which have not been provided for or would otherwise have a material impact on the Partnership's condensed 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.

-13-

Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

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

Partnership Overview

PDC 2003-A Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in April 2003 and operates 23 gross (11.4 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, 2011, 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 and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude 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

In June 2011, PDC acquired three affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership. PDC purchased these partnerships for the aggregate amount of $43.0 million.

On June 20, 2011, PDC and DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of PDC (“DP Merger Sub”), entered into separate merger agreements with this Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and PDC 2002-D Limited Partnership (collectively, the "2003 and 2002-D Partnerships"). PDC serves as the Managing General Partner of each of the 2003 and 2002-D Partnerships.

Pursuant to the 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 the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub, the separate existence of the Partnership will terminate and the non-affiliated investor partners will have the right to receive cash payments in the aggregate amount of $3,281,281 or $8,125 per limited partnership unit, subject to any adjustments made to the merger consideration for certain increases in commodity prices between the date of signing the merger agreement and the filing of the definitive proxy statement, plus the sum of the amounts withheld, if any, from per unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership's Well Refracturing Plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity. The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership's future earnings or any further economic benefit.

-14-

Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

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


•	should all parties agree by mutual consent to terminate the Merger Agreement;


•	by any party thereto, should the proposed merger not occur by December 15, 2011;


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


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


•	by the Special Committee, on behalf of the Partnership and prior to approval by non-affiliated investor partners, should the Special Committee believe it has received a superior offer that is more favorable to the non-affiliated investor partners; or


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

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

If the merger is not completed, the Partnership will continue the existing business plan to optimally develop and cost-effectively operate the Partnership's natural gas and oil reserves. This plan encompasses the implementation of the Well Refracturing Plan, more fully outlined below. The information presented in this Report on Form 10-Q for the six months ended June 30, 2011 and the year ended December 31, 2010 does not give effect to the proposed Merger Agreement.

Well Refracturing Plan

The Managing General Partner has prepared a plan for the Partnership's Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Well Refracturing Plan”). The Well Refracturing Plan consists of the Partnership's refracturing of wells currently producing in the Codell formation. Under the Well Refracturing Plan, the Partnership plans to initiate refracturing activities during 2013. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, all within an existing well bore.

-15-

Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Refracturing of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This refracturing would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refracture the individual wells and to determine the timing of any refracturing activity. The timing of the refracturing can be affected by the desire to optimize the economic return by refracturing the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. On average, the production resulting from PDC's Codell refracturings have been at modeled economics; however, all refracturings have not been economically successful and similar future refracturing activities may not be economically successful. If the refracturing work is performed, PDC will charge the Partnership for the direct costs of refracturing, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership's net cash flows provided by operating activities less any net cash used in capital activities.

During the fourth quarter 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing costs. This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years. This Partnership has not begun to withhold funds for refracturing as this Partnership has outstanding payables to the Managing General Partner.

Current estimated costs for these well refracturings are between $175,000 and $240,000 per activity. As of June 30, 2011, this Partnership had scheduled to complete 14 refracturing opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $1.2 million and $1.7 million. The Managing General Partner will continually evaluate the timing of commencing these refracturing activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. As of July 31, 2011, no funds have been withheld from the Partnership distributions pursuant to the Well Refracturing Plan.

If any or all of the Partnership's Wattenberg wells are not refractured, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the refracturing activities 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 scheduled Partnership refracturing activity will be completed within a five year period. Any funds not used for refracturing or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.

Implementation of the Well Refracturing Plan will reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership's funds. 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 future years. Non-affiliated 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 non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the Well Refracturing Plan.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 22% or approximately $84,000 for the first six months of 2011 compared to the first six months of 2010, while sales volumes declined 20% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.79 for the current year period compared to $5.90 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.08 per Mcfe or approximately $4,000 to the first six months of 2011 total revenues compared to an additional $1.28 or approximately $83,000 to the first six months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $5.87 for the current year six months from $7.18 for the same prior year period.

Direct costs −general and administrative increased by approximately $93,000 during the 2011 six month period due to increased fees for professional services.

-16-

Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

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



	Three months ended June 30,							Six months ended June 30,
	2011			2010		Change		2011			2010		Change
Number of producing wells (end of period)	23			23		—		23			23		—

Production⁽¹⁾
Natural gas (Mcf)	20,928			22,551		(7	)%	38,351			45,764		(16	)%
NGLs (Bbl)	233			295		(21	)%	469			619		(24	)%
Crude oil (Bbl)	849			1,209		(30	)%	1,759			2,585		(32	)%
Natural gas equivalents (Mcfe)⁽²⁾	27,420			31,575		(13	)%	51,719			64,988		(20	)%
Average Mcfe per day	301			347		(13	)%	286			359		(20	)%

Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	61,969		$	69,121	(10	)%	$	118,969		$	174,173	(32	)%
NGLs	9,815			10,433		(6	)%	20,609			23,694		(13	)%
Crude oil	80,304			86,499		(7	)%	159,809			185,801		(14	)%
Total natural gas, NGLs and crude oil sales	$	152,088		$	166,053	(8	)%	$	299,387		$	383,668	(22	)%

Realized Gain (Loss) on Derivatives, net
Natural gas	$	15,122		$	—	*		$	29,351		$	57,518	(49	)%
Crude oil	(14,492		)	13,263		(209	)%	(24,943		)	25,672		(197	)%
Total realized gain on derivatives, net	$	630		$	13,263	(95	)%	$	4,408		$	83,190	(95	)%

Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)⁽³⁾	$	2.96		$	3.07	(3	)%	$	3.10		$	3.81	(18	)%
NGLs (per Bbl)	42.12			35.37		19	%	43.94			38.28		15	%
Crude oil (per Bbl)	94.59			71.55		32	%	90.85			71.88		26	%
Natural gas equivalents (per Mcfe)	5.55			5.26		5	%	5.79			5.90		(2	)%

Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	3.68		$	3.07	20	%	$	3.87		$	5.06	(24	)%
NGLs (per Bbl)	42.12			35.37		19	%	43.94			38.28		15	%
Crude oil (per Bbl)	77.52			82.52		(6	)%	76.67			81.81		(6	)%
Natural gas equivalents (per Mcfe)	5.57			5.68		(2	)%	5.87			7.18		(18	)%

Average cost per Mcfe
Natural gas, NGLs and crude oil production cost⁽⁴⁾	$	2.29		$	1.95	17	%	$	2.27		$	1.81	25	%
Depreciation, depletion and amortization	$	3.25		$	3.13	4	%	$	3.33		$	3.14	6	%

Operating costs and expenses:
Direct costs - general and administrative	$	39,767		$	1,374	*		$	95,742		$	2,264	*
Depreciation, depletion and amortization	$	89,072		$	98,829	(10	)%	$	172,354		$	204,254	(16	)%

Cash distributions	$	7,649		$	168,482	(95	)%	$	14,359		$	386,901	(96	)%

*Percentage change not meaningful, equal to or greater than 250% or not calculable.

Amounts may not calculate due to rounding.

-17-

Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

_______________

⁽¹⁾ Production is net and determined by multiplying the gross production volume of properties in which the Partnership has an interest by the average percentage of the leasehold or other property interest the Partnership owns.

⁽²⁾ Six Mcf of natural gas equals one Bbl of crude oil or NGL.

⁽³⁾ The Partnership's average sales price for natural gas is based on the "net-back" method of accounting for transportation, gathering and processing arrangements with natural gas purchasers. See the Partnership's revenue recognition policy described in Note 2, Summary of Significant Accounting Policies, to financial statements in the Partnership's 2010 Form 10-K and Part 1, Item 2, Financial Condition, Liquidity and Capital Resources - Cash Flows, included in this report.

⁽⁴⁾ Production costs represent natural gas, NGLs and crude 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

Natural Gas, NGLs and Crude Oil Sales

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

For the six months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 20% due to normal production declines for this stage in the wells' production life cycle.

The approximately $84,000, or 22% decrease in sales for the 2011 six month period as compared to the prior year period, was primarily a reflection of sales volume decreases of 20% and a decline in sales prices of 2%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.79 for the current year six month period compared to $5.90 for the same period a year ago.

Natural gas, NGLs and crude oil revenues decreased by 32%, 13% and 14%, respectively. The Partnership's natural gas revenue decrease resulted from lower Partnership natural gas production volumes of 16% and from decreased commodity prices of 18%. The decrease in NGLs revenue was due to a decrease of 24% in NGLs production volumes, partially offset by increased commodity prices per Bbl of 15%. The crude oil revenue decrease is due primarily to sales volume decreases of 32%, partially offset by the rise in commodity prices per Bbl of 26% during the current six month period.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

For the three months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 13% due to normal production declines for this stage in the wells' production life cycle.

The approximately $14,000, or 8%, decrease in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of a sales volume decrease of 13% partially offset by an increase in sales prices of 5%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.55 for the current year three month period compared to $5.26 for the same period a year ago.

Natural gas, NGLs and crude oil revenues decreased by 10%, 6% and 7%, respectively. The Partnership's natural gas revenue decrease resulted from lower Partnership natural gas production volumes of 7%, and decreased commodity prices per Mcf of 3%. The decrease in NGLs revenue was due to a decrease of 21% in NGLs production volumes partially offset by increased commodity prices per Bbl of 19%. The crude oil revenue decrease is due primarily to a sales volume decrease of 30% partially offset by the rise in commodity prices per Bbl of 32% during the current three month period.

-18-

Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices. The Partnership has in place a variety of collars, fixed-price swaps and basis swaps on a portion of the Partnership's estimated natural gas and crude oil production. The Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership's derivative instruments. As a result, for the volumes underlying the Partnership's derivative positions, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership's commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.

Commodity price risk management, net, includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative instruments related to the Partnership's natural gas and crude oil production. See Note 4, Fair Value of Financial Instruments and Note 5, Derivative Financial Instruments, to the Partnership's unaudited condensed financial statements included in this report for additional details of the Partnership's derivative financial instruments.

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



	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Commodity price risk management gain, net:
Realized gains (losses)
Natural gas	$	15,122		$	—		$	29,351		$	57,518
Crude oil	(14,492		)	13,263			(24,943		)	25,672
Total realized gains, net	630			13,263			4,408			83,190

Unrealized gains (losses)
Reclassification of realized gains (losses) included in
prior periods unrealized	284			(9,094		)	(8,301		)	(49,078		)
Unrealized gains for the period	38,380			61,934			17,931			201,111
Total unrealized gains, net	38,664			52,840			9,630			152,033
Total commodity price risk management gain, net	$	39,294		$	66,103		$	14,038		$	235,223

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Realized gains recognized in the six months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $68,000 for the six months ended June 30, 2011. These gains were offset in part by an approximate $39,000 loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions. The Partnership also realized an approximate $25,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the six months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of approximately $34,000 which was partially offset by unrealized losses of approximately $13,000 on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow. Additionally, the shifts upward in the crude oil curves resulted in an unrealized loss of approximately $3,000.

The realized derivative gains for the 2010 six month period were approximately $83,000. These realized gains were primarily a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the six month period, realized gains related to natural gas and oil derivatives were approximately $82,000 and $26,000, respectively, and realized losses on the Partnership's CIG basis protection swaps were approximately $25,000. Unrealized gains for the six month period, were approximately $201,000 due primarily to a downward shift in the natural gas and oil forward curves. Unrealized gains on the Partnership's natural gas and oil positions for the period were approximately $177,000 and $24,000, respectively.

-19-

Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Realized gains recognized in the three months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $40,000 for the three months ended June 30, 2011. These gains were offset in part by an approximate $25,000 loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized an approximate $14,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the three months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shift downward in the crude oil curve resulted in an unrealized gain of approximately $10,000 during the three months ended June 30, 2011. Likewise, the shifts downward in the natural gas and basis curves resulted in a total unrealized gain of approximately $28,000.

The realized derivative gains for the 2010 second quarter were approximately $13,000. These realized gains are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the quarter, realized gains related to natural gas and oil derivatives were approximately $38,000 and realized losses on the Partnership's CIG basis swaps were approximately $25,000. For the 2010 second quarter, the unrealized gains were primarily related to the oil positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential. Unrealized gains on the Partnership's oil positions and CIG basis protection swaps for the 2010 second quarter were approximately $26,000 and $30,000, respectively. Additionally, the shifts downward in the natural gas curves resulted in an unrealized gain of approximately $6,000.

The following table presents the Partnership's derivative positions in effect as of June 30, 2011.



	Collars					Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price				Quantity (Gas-MMBtu⁽¹⁾ Oil-Bbls)	Weighted Average Contract Price		Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price			Fair Value at June 30, 2011⁽²⁾
		Floors		Ceilings

Natural Gas
NYMEX
07/01 - 09/30/2011	—	$	—	$	—	16,224	$	6.73	16,224	$	(1.88	)	$	13,242
10/01 - 12/31/2011	—	—		—		15,890	6.78		15,890	(1.88		)	10,334
01/01 - 03/31/2012	1,177	6.00		8.27		14,262	6.98		15,439	(1.88		)	8,625
04/01 - 06/30/2012	638	6.00		8.27		14,588	6.98		15,226	(1.88		)	12,385
07/01 - 12/31/2012	1,811	6.00		8.27		28,127	6.98		29,938	(1.88		)	17,242
2013	—	—		—		56,436	7.12		56,436	(1.88		)	29,620
Total Natural Gas	3,626					145,527			149,153				91,448

Crude Oil
NYMEX
07/01 - 09/30/2011	—	—		—		465	70.75		—	—			(11,385		)
10/01 - 12/31/2011	—	—		—		474	70.75		—	—			(12,278		)
Total Crude Oil	—					939			—				(23,663		)

Total Natural Gas and Crude Oil													$	67,785

⁽¹⁾A standard unit of measure for natural gas (one MMBtu equals one Mcf).

⁽²⁾Approximately 2% of the fair value of the Partnership's derivative assets and none of the Partnership's derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 4, Fair Value of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.

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Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Natural Gas, NGLs and Crude Oil Production Costs

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

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Production and operating costs per Mcfe increased to $2.27 during the current period compared to $1.81 for the prior year period due to the effect of the fixed monthly well operating costs increases on a per unit basis as production volumes declined. Current period production and operating costs include a workover performed at one of the Partnership's Piceance wells, of which this cost was partially offset by decreases in production taxes and transportation costs due to lower sales revenue and volumes compared to the prior period.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Production and operating costs per Mcfe increased to $2.29 during the current period compared to $1.95 for the prior year period due to the effect of the fixed monthly well operating costs increases on a per unit basis as production volumes declined.

Direct Costs−General and Administrative

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs increased during the six months ended June 30, 2011 compared to the same period in 2010, by approximately $93,000 principally due to increased fees for professional services.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs increased during the three months ended June 30, 2011 compared to the same period in 2010, by approximately $38,000 principally due to increased fees for professional services.

Depreciation, Depletion and Amortization

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

The DD&A expense rate per Mcfe increased to $3.33 for the 2011 six month period, compared to $3.14 during the same period in 2010. The increase in the per Mcfe rates for the 2011 period compared to the 2010 period is due to the changing production mix between the Partnership's Wattenberg and Grand Valley Fields, which have significantly different DD&A rates, as well as the effect of the downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves particularly in the Grand Valley Field as of December 31, 2010. The production declines, noted in previous sections, partially offset by the increased DD&A expense rate, resulted in a decreased DD&A expense of approximately $32,000 for the 2011 six month period compared to the same 2010 period.

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Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

The DD&A expense rate per Mcfe increased to $3.25 for the 2011 three month period, compared to $3.13 during the same period in 2010. The increase in the per Mcfe rates for the 2011 period compared to the 2010 period is due to the effect of the downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves particularly in the Grand Valley Field as of December 31, 2010. The production declines, noted in previous sections, partially offset by the increased DD&A expense rate, resulted in a decreased DD&A expense of approximately $10,000 for the 2011 three month period compared to the same 2010 period.

Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for the six months ended June 30, 2011 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude 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 provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. Additionally, the Partnership's operating cash flows were reduced by approximately $76,000 due to payments by the Partnership to reduce the balance of Due to the Managing General Partner-other, net (See Working Capital below). The future repayment of the entire balance of Due to the Managing General Partner-other, net prior to withholding any distributions to fund the Well Refracturing Plan was taken into consideration when assessing the Partnership's ability to complete this plan. When this balance is repaid, any future withholdings would provide the funding for planned Wattenberg Field well refracturing costs to be incurred beginning in 2013. For additional information, see Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments- Well Refracturing Plan.

Fluctuations in the Partnership's operating cash flows 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 Managing General Partner 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, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments 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, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 85% of the expected natural gas production and 44% of expected crude oil production for the remainder of 2011, at an average price of $4.87 per Mcf and $70.75 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 first quarter of 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price market. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership's revenues.

The Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. Natural gas, NGLs and crude oil production from the Partnership's existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, 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 2011 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the refracturing activities which are more fully described in Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.

Working Capital

The Partnership had negative working capital of approximately $0.4 million and $0.5 million at June 30, 2011 and December 31, 2010, respectively. The Partnership's working capital deficit decreased by approximately $0.1 million due to payments to the Managing General Partner. This deficit arose in the third and fourth quarters of 2010 due primarily to the increase to Direct costs - general and administrative resulting from the Partnership's SEC compliance effort. These costs were in excess of cash provided by operating activities during that period and were paid by the Managing General Partner and are being repaid by the Partnership.

Working capital is expected to fluctuate by increasing during periods of Well Refracturing Plan funding and by decreasing during periods when payments are made for refracturing.

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Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Cash Flows

Cash Flows From Operating Activities

The Partnership's cash flows provided by operating activities are primarily impacted by commodity prices, production volumes, realized gains and losses from its derivative positions, operating costs and general and administrative expenses. See Results of Operations above for an additional discussion of the key drivers of cash flows provided by operating activities.

Natural gas, NGLs and crude oil prices exhibit a high degree of volatility. These price variations have a material impact on the Partnership's financial results. Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets has 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 beyond the Partnership's control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have 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. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential of CIG relative to NYMEX averaged $0.31 and $0.32 for the six months ended June 30, 2011 and 2010, respectively.

The price the Partnership receives on its natural gas sales is impacted by the Managing General Partner's transportation, gathering and processing agreements. The Partnership currently uses the "net-back" method of accounting for these arrangements related to the Partnership's natural gas sales. The Partnership sells natural 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 purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

Net cash provided by operating activities was approximately $16,000 for the six months ended June 30, 2011, compared to approximately $388,000 for the comparable period in 2010. The decrease of approximately $372,000 in cash provided by operating activities was due primarily to the following:


•	A decrease in natural gas, NGLs and crude oil sales receipts of approximately $110,000, or 27%,


•	A decrease in commodity price risk management realized gains receipts of approximately $110,000, or 84%, and


•	An increase in production costs and direct costs - general and administrative payments of approximately $150,000.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts were not significant for the six months ended June 30, 2011 and 2010, respectively.

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Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in November 2003 and has distributed $9.3 million through June 30, 2011. The table below presents cash distributions to the Partnership's investors. Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner's 20% ownership share in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.



Distributions

Three months ended June 30,	Managing General Partner		Investor Partners		Total
2011	$	1,530	$	6,119	$	7,649
2010	$	33,697	$	134,785	$	168,482

Six months ended June 30,	Managing General Partner		Investor Partners		Total
2011	$	2,872	$	11,487	$	14,359
2010	$	77,381	$	309,520	$	386,901

The decrease in total distributions for 2011 as compared to 2010 is primarily due to the significant decrease in cash flows from operating activities during 2011.

Off-Balance Sheet Arrangements

As of June 30, 2011, the Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on the Partnership's financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

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

Recent Accounting Standards

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

Critical Accounting Policies and Estimates

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

There have been no significant changes to the Partnership's critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership's 2010 Form 10-K.

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Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of June 30, 2011, PDC, as Managing General Partner on behalf 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 Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that the Partnership files or submits under the Exchange Act is 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 disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of June 30, 2011.

(b) Changes in Internal Control over Financial Reporting

During the three months ended June 30, 2011, 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 Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership's internal control over financial reporting.

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Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

Not applicable.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unit 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.

The following table presents information about the Managing General Partner's limited partner unit repurchases during the three months ended June 30, 2011.



Period	Total Number of Units Repurchased	Average Price Paid Per Unit
April 2011	0.75	$	2,413
May 2011	—	—
June 2011	—	—
Total second quarter repurchases	0.75

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

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Index

PDC 2003-A Limited Partnership

(A West Virginia Limited Partnership)

Item 6. Exhibits

The exhibits presented below are in addition to those presented in the Partnership's Form 10-K and subsequent quarterly filings on Form 10-Q.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

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 the Sarbanes-Oxley Act of 2002.

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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/ James M. Trimble
	James M. Trimble Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy)
	August 12, 2011

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/ James M. Trimble	Chief Executive Officer	August 12, 2011
James M. Trimble	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	August 12, 2011
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	August 12, 2011
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal accounting officer)

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PDC 2003-A LP 10-Q