UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

OF 1934

For the quarterly period ended March 31, 2011

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

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-50615

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 þ 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 ¨ 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 o	Accelerated filer o
	Non-accelerated filer ¨	Smaller reporting company þ

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

As of March 31, 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

		Page
	PART I – FINANCIAL INFORMATION

	Special Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	3
	Condensed Statements of Operations (unaudited)	4
	Condensed Statements of Cash Flows (unaudited)	5
	Notes to Unaudited Condensed Financial Statements	6
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 Index	24

	SIGNATURES	25

Index

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report 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, which include statements of estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including 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 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

the effect of existing and future laws, governmental regulations and the political and economic climate of the U.S. as well as other oil producing countries throughout the world;

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;

competition in the oil and gas industry;

the success of the Managing General Partner in marketing the Partnership’s oil and gas;

the effect of natural gas and crude oil derivative activities;

the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;

losses possible from pending or future litigation; and

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

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PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 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.

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Index

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PDC 2003-A Limited Partnership
Condensed Balance Sheets
(unaudited)


	March 31, 2011				December31, 2010*
Assets

Current assets:
Cash and cash equivalents	$	10,224		$	10,221
Accounts receivable		64,480			68,082
Crude oil inventory		12,674			12,237
Due from Managing General Partner-derivatives		134,087			127,068
Total current assets		221,465			217,608


Natural gas and crude oil properties, successful efforts method, at cost		9,370,075			9,368,764
Less: Accumulated depreciation, depletion and amortization		(5,806,194	)		(5,722,912	)
Natural gas and crude oil properties, net		3,563,881			3,645,852

Due from Managing General Partner-derivatives		178,338			207,714
Other assets		27,598			25,895
Total noncurrent assets		3,769,817			3,879,461

Total Assets	$	3,991,282		$	4,097,069

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	6,960		$	14,120
Due to Managing General Partner-derivatives		142,905			119,159
Due to Managing General Partner-other, net		563,670			590,455
Total current liabilities		713,535			723,734

Due to Managing General Partner-derivatives		140,399			157,468
Asset retirement obligations		120,170			118,420
Total liabilities		974,104			999,622

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		604,728			620,782
Limited Partners - 424.15 units issued and outstanding		2,412,450			2,476,665
Total Partners' equity		3,017,178			3,097,447

Total Liabilities and Partners' Equity	$	3,991,282		$	4,097,069

*Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

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PDC 2003-A Limited Partnership
Condensed Statements of Operations
(unaudited)


	Three months ended March 31,
	2011			2010
Revenues:
Natural gas, NGLs and crude oil sales	$	147,299		$	217,615
Commodity price risk management (loss) gain, net		(25,256	)		169,120
Total revenues		122,043			386,735

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs		54,599			56,288
Direct costs - general and administrative		55,975			890
Depreciation, depletion and amortization		83,282			105,425
Accretion of asset retirement obligations		1,750			1,650
Total operating costs and expenses		195,606			164,253

(Loss) income from operations		(73,563	)		222,482

Interest income		4			-

Net (loss) income	$	(73,559	)	$	222,482

Net (loss) income allocated to partners	$	(73,559	)	$	222,482
Less: Managing General Partner interest in net (loss) income		(14,712	)		44,496
Net (loss) income allocated to Investor Partners	$	(58,847	)	$	177,986

Net (loss) income per Investor Partner unit	$	(139	)	$	420

Investor Partner units outstanding		424.15			424.15

See accompanying notes to unaudited condensed financial statements.

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PDC 2003-A Limited Partnership
Condensed Statements of Cash Flows
(unaudited)


	Three months ended March 31,
	2011			2010
Cash flows from operating activities:
Net (loss) income	$	(73,559	)	$	222,482
Adjustments to net (loss) income to reconcile to net cash
provided by operating activities:
Depreciation, depletion and amortization		83,282			105,425
Accretion of asset retirement obligations		1,750			1,650
Unrealized loss (gain) on derivative transactions		29,034			(99,193	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		3,602			(1,063	)
(Increase) decrease in crude oil inventory		(437	)		492
Increase in other assets		(1,703	)		(1,703	)
Decrease in accounts payable an accrued expenses		(7,160	)		-
Increase in Due from Managing General Partner - other, net		-			(8,396	)
Decrease in Due to Managing General Partner - other, net		(26,785	)		-
Net cash provided by operating activities		8,024			219,694

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties		(1,311	)		(1,299	)
Net cash used in investing activities		(1,311	)		(1,299	)

Cash flows from financing activities:
Distributions to Partners		(6,710	)		(218,419	)
Net cash used in financing activities		(6,710	)		(218,419	)

Net increase (decrease) in cash and cash equivalents		3			(24	)
Cash and cash equivalents, beginning of period		10,221			133
Cash and cash equivalents, end of period	$	10,224		$	109

See accompanying notes to unaudited condensed financial statements.

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PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 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 March 31, 2011, there were 432 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 Limited Partnership 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 March 31, 2011, the Managing General Partner has repurchased 19.6 units of Partnership interests from Investor Partners at an average price of $8,449 per unit. As of March 31, 2011, the Managing General Partner owns 23.7% 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 months ended March 31, 2011, and the cash flows for the same period, 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 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.

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PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2011

(unaudited)

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.

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.

	March 31,			December 31,
	2011			2010

Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	37,925		$	33,561
Commodity price risk management, realized gain		1,592			18,247
Other (1)		(603,187	)		(642,263	)
Total Due to Managing General Partner-other, net	$	(563,670	)	$	(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 months ended March 31, 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 March 31,
	2011		2010

Well operations and maintenance	$	43,820	$	41,186
Gathering, compression and processing fees		4,004		5,746
Direct costs - general and administrative		55,975		890
Cash distributions (1)		1,590		51,238

(1)

Cash distributions include $248 and $7,554 during the three months ended March 31, 2011 and 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

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PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2011

(unaudited)

Note 4− Fair Value of Financial Instruments

The following table presents, for each hierarchy level, the Partnership’s derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010.

	March 31, 2011								December 31, 2010
	Quoted Prices in		Significant						Quoted Prices in		Significant
	Active Markets		Unobservable Inputs						Active Markets		Unobservable Inputs
	Level 1		Level 3			Total			Level 1		Level 3			Total

Assets:
Commodity based derivatives	$	308,220	$	4,205		$	312,425		$	321,245	$	13,537		$	334,782
Total assets		308,220		4,205			312,425			321,245		13,537			334,782

Liabilities:
Commodity based derivatives		-		(50,094	)		(50,094	)		-		(40,635	)		(40,635	)
Basis protection derivative contracts		-		(233,210	)		(233,210	)		-		(235,992	)		(235,992	)
Total liabilities		-		(283,304	)		(283,304	)		-		(276,627	)		(276,627	)

Net asset (liability)	$	308,220	$	(279,099	)	$	29,121		$	321,245	$	(263,090	)	$	58,155

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

	Three months ended
	March 31, 2011			March 31, 2010
Fair value, net liability, beginning of year	$	(263,090	)	$	(208,883	)
Changes in fair value included in statement of operations line item -
Commodity price risk management, net		(28,976	)		(22,779	)
Settlements		12,967			(69,927	)
Fair value, net liability, end of period	$	(279,099	)	$	(301,589	)

Change in unrealized loss relating to assets (liabilities) still
held as of March 31, 2011 and 2010, respectively,
included in statement of operations line item:
Commodity price risk management, net	$	(28,406	)	$	(28,090	)

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.

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PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2011

(unaudited)

Note 5− Derivative Financial Instruments

As of March 31, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 165,509 MMbtu of natural gas and 1,395 Bbls 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
		Balance Sheet	March 31,		December 31,
Derivative instruments not designated as hedge (1):		Line Item	2011		2010

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	134,087	$	127,068

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		178,338		207,714


Total Derivative Assets			$	312,425	$	334,782

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	50,094	$	40,635

	Basis protection contracts	Due to Managing General Partner-derivatives		92,811		78,524

	Non Current

	Basis protection contracts	Due to Managing General Partner-derivatives		140,399		157,468

Total Derivative Liabilities			$	283,304	$	276,627

(1)

As of March 31, 2011 and December 31, 2010, none of the Partnership’s derivative instruments were designated as hedges.

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

	Three months ended March 31,
	2011									2010
Statement of operations line item	Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized			Realized and Unrealized Gain (Loss) For the Current Period			Total			Reclassification of Realized Loss (Gain) Included in Prior Periods Unrealized			Realized and Unrealized Gain For the Current Period		Total

Commodity price risk management, net
Realized gain	$	2,670		$	1,108		$	3,778		$	64,616		$	5,311	$	69,927
Unrealized (loss) gain		(2,670	)		(26,364	)		(29,034	)		(64,616	)		163,809		99,193
Total commodity price risk management (loss) gain, net	$	-		$	(25,256	)	$	(25,256	)	$	-		$	169,120	$	169,120

Derivative Counterparties. 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.

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PDC 2003-A LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 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 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 three months ended March 31, 2011, there were no new environmental remediation projects identified by the Managing General Partner related to the Partnership. As of March 31, 2011, and December 31, 2010, the Partnership has accrued environmental remediation liabilities for one Partnership well in the amount of $1,500 and $9,000, respectively, which is included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets. The Managing General Partner is not aware of any environmental claims existing as of March 31, 2011, 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.

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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 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 March 31, 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

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 the particular partnership other than those held by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously 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, the economics of the merger 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 limited partnership under the Acquisition Plan will 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 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. The special meetings whereby non-affiliated investor partners of the 2005 Partnerships will have an opportunity to vote and approve the respective merger agreements are currently scheduled for June 15, 2011.

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PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The feasibility and timing of any future purchase offer by PDC to any additional partnership, 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 productive-life stage characteristics of the partnership’s well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated with gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any merger and acquisition will occur, 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.

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.

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 refrac 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 this additional Codell formation development 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 March 31, 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 April 30, 2011, no funds have been withheld from the Partnership distributions for this refracturing.

-12-

Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 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 32% or $70,000 for the first three months of 2011 compared to the first three months of 2010, while sales volumes declined 27% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.06 for the current year period compared to $6.51 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.16 per Mcfe or $4,000 to the first three months of 2011 total revenues compared to an additional $2.10 or $70,000 to the first three months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $6.22 for the current year three months from $8.61 for the same prior year period.

Direct costs−general and administrative increased by $55,000 during the 2011 three month period due to increased fees for professional services.

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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 March 31,
	2011			2010		Change
Number of producing wells (end of period)		23			23		-

Production(1)
Natural gas (Mcf)		17,423			23,213		-25	%
NGLs (Bbl)		236			324		-27	%
Crude oil (Bbl)		910			1,376		-34	%
Natural gas equivalents (Mcfe)(2)		24,299			33,413		-27	%
Average Mcfe per day		270			371		-27	%

Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	57,000		$	105,052		-46	%
NGLs		10,794			13,261		-19	%
Crude oil		79,505			99,302		-20	%
Total natural gas, NGLs and crude oil sales	$	147,299		$	217,615		-32	%

Realized Gain (Loss) on Derivatives, net
Natural gas	$	14,230		$	57,518		-75	%
Crude oil		(10,452	)		12,409		-184	%
Total realized gain on derivatives, net	$	3,778		$	69,927		-95	%

Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	3.27		$	4.53		-28	%
NGLs (per Bbl)		45.74			40.93		12	%
Crude oil (per Bbl)		87.37			72.17		21	%
Natural gas equivalents (per Mcfe)		6.06			6.51		-7	%

Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	4.09		$	7.00		-42	%
NGLs (per Bbl)		45.74			40.93		12	%
Crude oil (per Bbl)		75.88			81.19		-7	%
Natural gas equivalents (per Mcfe)		6.22			8.61		-28	%

Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	2.25		$	1.68		33	%
Depreciation, depletion and amortization		3.43			3.16		9	%

Operating costs and expenses:
Direct costs - general and administrative	$	55,975		$	890		*
Depreciation, depletion and amortization		83,282			105,425		-21	%

Cash distributions	$	6,710		$	218,419		-97	%

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

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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)

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

For the three months ended March 31, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 27% due to normal production declines for this stage in the wells’ production life cycle and equipment problems at one Partnership producing well.

Three months ended March 31, 2011 as compared to three months ended March 31, 2010

The $70,000, or 32%, 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 27% and a decline in sales prices of 7%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.06 for the current year three month period compared to $6.51 for the same period a year ago.

Natural gas, NGLs and crude oil revenues decreased by 46%, 19% and 20%, respectively. The Partnership’s natural gas revenue decrease resulted from decreased commodity prices per Mcf, of 28%, and lower Partnership natural gas production volumes of 25%. The decrease in NGLs revenue was due to a decrease of 27% in NGLs production volumes partially offset by increased commodity prices per Bbl, of 12%. The crude oil revenue decrease is due primarily to a sales volume decrease of 34% partially offset by the rise in commodity prices per Bbl, of 21% during the current three month period.

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 floors, collars, fixed-price swaps and basis swaps on a portion of the Partnership’s estimated natural gas and crude oil production. Because the Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership’s derivative instruments, 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.

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Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

	Three months ended March 31,
Commodity price risk management, net	2011			2010
Realized gain (loss)
Natural gas	$	14,230		$	57,518
Crude oil		(10,452	)		12,409
Total realized gain, net		3,778			69,927

Unrealized gain (loss)
Reclassification of realized gain included in
prior periods unrealized		(2,670	)		(64,616	)
Unrealized (loss) gain for the period		(26,364	)		163,809
Total unrealized (loss) gain, net		(29,034	)		99,193
Commodity price risk management (loss) gain, net	$	(25,256	)	$	169,120

Three months ended March 31, 2011 as compared to three months ended March 31, 2010

Realized gains recognized in the three months ended March 31, 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 $27,000 for the three months ended March 31, 2011. These gains were offset in part by a $13,000 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 a $10,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized losses during the three months ended March 31, 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 significant shift upward in the crude oil curve resulted in an unrealized loss of $18,000 during the three months ended March 31, 2011. Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of $8,000.

During the three months ended March 31, 2010, the Partnership recorded realized gains of $70,000 as a result of natural gas and crude oil spot prices being lower at settlement compared to the respective strike price. During the three months ended March 31, 2010, the Partnership recorded unrealized gains of $164,000, of which $198,000 was related to the Partnership’s natural gas and crude oil positions, partially offset by unrealized losses on the Partnership’s CIG basis protection swaps of $34,000 as the forward basis differential between NYMEX and CIG had continued to narrow.

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Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table presents the Partnership’s derivative positions in effect as of March 31, 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 March 31, 2011(2)
Commodity/ Index	Quantity (Gas- MMbtu(1))		Floors		Ceilings		Quantity (Gas-MMbtu(1) Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas- MMbtu(1))		Weighted Average Contract Price			Fair Value at March 31, 2011(2)

Natural Gas
NYMEX
04/01 - 06/30/2011		-	$	-	$	-		16,354	$	6.78		16,354	$	(1.88	)	$	15,867
07/01 - 09/30/2011		-		-		-		16,224		6.73		16,224		(1.88	)		11,896
10/01 - 12/31/2011		-		-		-		15,890		6.78		15,890		(1.88	)		8,618
01/01 - 03/31/2012		1,177		6.00		8.27		14,263		6.98		15,439		(1.88	)		4,895
04/01 - 12/31/2012		2,449		6.00		8.27		42,716		6.98		45,164		(1.88	)		21,898
2013		-		-		-		56,436		7.12		56,436		(1.88	)		16,043
Total Natural Gas		3,626						161,883				165,507					79,217

Crude Oil
NYMEX
04/01 - 06/30/2011		-		-		-		456		70.75		-		-			(16,152	)
07/01 - 09/30/2011		-		-		-		465		70.75		-		-			(16,817	)
10/01 - 12/31/2011		-		-		-		474		70.75		-		-			(17,127	)
Total Crude Oil		-						1,395				-					(50,096	)

Total Natural Gas and Crude Oil																$	29,121

(1)

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

(2)

Approximately 1% 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 of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.

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.

Three months ended March 31, 2011 as compared to three months ended March 31, 2010

Production and operating costs per Mcfe increased to $2.25 during the current period compared to $1.68 for the prior year period due to the effect of higher per-well related expenditures partially offset by lower per-volume related natural gas, NGLs and crude oil production costs. Current period production and operating costs decreased by approximately $2,000, primarily due to reductions in production taxes, natural gas transportation and lease operating expenses resulting from decreased production volumes and lower sales as compared to the same period in 2010.

Direct Costs−General and Administrative

Three months ended March 31, 2011 as compared to three months ended March 31, 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 March 31, 2011, compared to the same period in 2010, by approximately $55,000 principally due to increased fees for the above referenced professional services.

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Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Depreciation, Depletion and Amortization

Three months ended March 31, 2011 as compared to three months ended March 31, 2010

The DD&A expense rate per Mcfe increased to $3.43 for the 2011 three month period, compared to $3.16 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 $22,000 for the 2011 three month period compared to the same 2010 period.

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Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Condition, Liquidity and Capital Resources

The Partnership’s primary sources of cash for the three months ended March 31, 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. Any future withholdings would provide the funding for planned Wattenberg Field refracturing costs to be incurred during 2013, and thereafter and are expected to decrease distributions from historical levels.

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 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 March 31, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 64% of the expected natural gas production and 33% of expected crude oil production for the remainder of 2011, at an average price of $4.88 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 2010 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.

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 $0.5 million at both March 31, 2011 and December 31, 2010. The Partnership’s working capital deficit remained unchanged as net cash provided by operations was used to fund investing activities and for cash distributions to the Partners. 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 remain unpaid 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 is 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 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 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 $0.28 and $0.16 for the three months ended March 31, 2011 and 2010, respectively.

Net cash provided by operating activities was approximately $8,000 for the three months ended March 31, 2011, compared to approximately $220,000 for the comparable period in 2010. The approximately $212,000 decrease in cash provided by operating activities was due primarily to the following:

A decrease in natural gas, NGLs and crude oil sales receipts of $70,000, or 33%,

A decrease in commodity price risk management realized gains receipts of $60,000, or 74% , and

An increase in production costs and direct costs – general and administrative payments of $80,000.

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 totaled approximately $1,000 each for the three months ended March 31, 2011 and 2010.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in November 2003 and has distributed $9.3 million through March 31, 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.

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Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Quarter	Managing		Investor
ended	General Partner		Partners		Total
March 31,	Distributions		Distributions		Distributions

2011	$	1,342	$	5,368	$	6,710

2010	$	43,684	$	174,735	$	218,419

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 March 31, 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 March 31, 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 March 31, 2011.

(b) Changes in Internal Control over Financial Reporting

During the three months ended March 31, 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 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 March 31, 2011.

			Average Price
	Total Number of		Paid per
Period	Units Repurchased		Unit

January 1−31, 2011		0.25	$	3,740
February 1−28, 2011		-		-
March 1−31, 2011		-		-
Total first quarter Unit Repurchase Program repurchases		0.25

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

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Index

PDC 2003-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6. Exhibits Index

The exhibits presented below are in addition to those presented in the Partnership’s Form 10-K.

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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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)

May 10, 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/ Richard W. McCullough	Chairman and Chief Executive Officer	May 10, 2011
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	May 10, 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	May 10, 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