CONFORMED COPY

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

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

FORM 10-Q

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

For the ~~Securities Exchange~~quarterly ~~Act~~period ofended ~~1934~~March 31, 2010

For the period ended March 31, 2005

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

~~the~~FOR ~~Securities Exchange~~THE ~~Act~~TRANSITION ~~of 1934~~PERIOD ____________ TO ____________

~~For~~Commission ~~the~~File ~~transition period from to~~Number 000-50618

~~Commission~~PDC ~~file number 000~~2003-~~50618~~D Limited Partnership (Exact name of registrant as specified in its charter)

West Virginia (State or other jurisdiction of incorporation or organization) 56-2348528 (I.R.S. Employer Identification ~~Number 56-2348528~~No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203
(Address of principal executive offices) (Zip code)

(303) 860-5800
(Registrant’s telephone number, including area code)

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

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

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


	Large accelerated filer o	Accelerated filer o

	Non-accelerated filer o	Smaller reporting company x

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

As of March 31, 2010 the Partnership had 1,749.84 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Bridgeport, WV 26330

		Page
	PART I – FINANCIAL INFORMATION

	Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	2
	Condensed Statements of Operations (unaudited)	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	Controls and Procedures	21

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	22
Item 1A.	Risk Factors	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
Item 3.	Defaults Upon Senior Securities	22
Item 4.	[Removed and Reserved]	22
Item 5.	Other Information	22
Item 6.	Exhibits	23

	SIGNATURES	24

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

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

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

All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“PDC”) strategies, plans and objectives. However, these words are not the exclusive means of identifying forward-looking statements herein. PDC now conducts business under the name “PDC Energy.”

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

●

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

●

changes in estimates of proved reserves;

●

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

●

the timing and extent of the Partnership’s success in further developing and producing the Partnership’s natural gas and oil reserves;

●

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

●

risks incident to the additional Codell formation development and operation of natural gas and oil wells;

●

future production and additional Codell formation development costs;

●

the availability of Partnership future cash flows for investor distributions or funding of Additional Codell Formation Development Plan activities;

●

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

●

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

●

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

●

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

●

the effect of natural gas and oil derivatives activities;

●

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

●

conditions in the capital markets; and

●

losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report, the Partnership’s annual reports on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission, or SEC, on October 12, 2010 (“2009 Form 10-K”) and the Partnership’s other filings with the SEC and public disclosures. The Partnership cautions you not to place undue reliance on forward-looking statements, which speak only as of the date made. Other than as required under the securities laws, the Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

- 1 -

Index

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements(unaudited)

PDC 2003-D Limited Partnership

Condensed Balance Sheets

(unaudited)


	March 31, 2010			December 31, 2009*
Assets

Current assets:
Cash and cash equivalents	$	107,620		$	107,580
Accounts receivable		191,251			182,034
Oil inventory		30,350			32,469
Due from Managing General Partner-derivatives		395,188			332,812
Due from Managing General Partner-other, net		389,457			440,146
Total current assets		1,113,866			1,095,041


Natural gas and oil properties, successful efforts method, at cost		26,985,077			26,982,833
Less: Accumulated depreciation, depletion and amortization		(14,684,499	)		(14,239,379	)
Oil and gas properties, net		12,300,578			12,743,454

Due from Managing General Partner-derivatives		767,190			307,821
Other assets		63,202			57,235
Total noncurrent assets		13,130,970			13,108,510

Total Assets	$	14,244,836		$	14,203,551

Liabilities and Partners’ Equity

Current liabilities:
Accounts payable and accrued expenses	$	31,714		$	20,551
Due to Managing General Partner-derivatives		353,981			297,960
Total current liabilities		385,695			318,511

Due to Managing General Partner-derivatives		965,441			906,376
Asset retirement obligations		405,403			399,463
Total liabilities		1,756,539			1,624,350

Commitments and contingent liabilities

Partners’ equity:
Managing General Partner		2,502,649			2,520,829
Limited Partners - 1,749.84 units issued and outstanding		9,985,648			10,058,372
Total Partners’ equity		12,488,297			12,579,201

Total Liabilities and Partners’ Equity	$	14,244,836		$	14,203,551

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-D Limited Partnership

Condensed Statements of Operations

(unaudited)


	Three months ended March 31,
	2010		2009
Revenues:
Natural gas and oil sales	$	697,772	$	411,917
Commodity price risk management gain (loss), net		674,565		(30,044	)
Total revenues		1,372,337		381,873

Operating costs and expenses:
Natural gas and oil production costs		328,340		285,334
Direct costs - general and administrative		1,153		6,372
Depreciation, depletion and amortization		445,120		500,354
Accretion of asset retirement obligations		5,940		4,042
Total operating costs and expenses		780,553		796,102

Income (loss) from operations		591,784		(414,229	)

Interest income		40		13,770

Net income (loss)	$	591,824	$	(400,459	)

Net income (loss) allocated to partners	$	591,824	$	(400,459	)
Less: Managing General Partner interest in net income (loss)		118,365		(80,092	)
Net income (loss) allocated to Investor Partners	$	473,459	$	(320,367	)

Net income (loss) per Investor Partner unit	$	271	$	(183	)

Investor Partner units outstanding		1,749.84		1,749.84

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-D Limited Partnership

Condensed Statements of Cash Flows

(unaudited)


	Three months ended March 31,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	591,824		$	(400,459	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		445,120			500,354
Accretion of asset retirement obligations		5,940			4,042
Unrealized (gain) loss on derivative transactions		(406,659	)		536,242
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(9,217	)		94,865
Decrease in oil inventory		2,119			17,947
Increase in other assets		(5,967	)		(6,139	)
Increase (decrease) in accounts payable and accrued expenses		11,163			(23,586	)
Decrease (increase) in Due from Managing General Partner - other, net		50,689			(147,421	)
Net cash provided by operating activities		685,012			575,845

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(2,244	)		(66,481	)
Net cash used in investing activities		(2,244	)		(66,481	)

Cash flows from financing activities:
Distributions to Partners		(682,728	)		(508,271	)
Net cash used in financing activities		(682,728	)		(508,271	)

Net increase in cash and cash equivalents		40			1,093
Cash and cash equivalents, beginning of period		107,580			106,325
Cash and cash equivalents, end of period	$	107,620		$	107,418

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2003-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2003-D Limited Partnership (the “Partnership”) was organized as a limited partnership on September 25, 2003, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties. Upon completion of the sale of Partnership units on December 15, 2003 the Partnership was funded and commenced its business operations. The Partnership owns natural gas and oil wells located in Colorado, and from the wells, the Partnership produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 14.50 units of limited partner interests and 1,735.34 units of additional general partner interests at $20,000 per unit. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a Nevada Corporation that now conducts business under the name “PDC Energy,” is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner” or “PDC”) and has a 20% Managing General Partner ownership in the Partnership. Upon completion of the drilling phase of the Partnership’s wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 20% to the Managing General Partner.

As of March 31, 2010, there were 1,226 Investor Partners. As of March 31, 2010 the Managing General Partner has repurchased 41.84 units of the total 1,749.84 outstanding units of Partnership interests from Investor Partners at an average price of $5,749 per unit and, as a result, participates in the sharing of revenues, costs and cash distributions as both an investor partner and as the Managing General Partner.

The Managing General Partner, under the terms of the Drilling and Operating Agreement (the “D&O Agreement”), has full authority to conduct the Partnership’s business and actively manage the Partnership. The Partnership expects continuing operations of its natural gas and oil properties until such time that the Partnership’s wells are depleted or become uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the Agreement (which are unlikely to occur at this time) or by written consent of the Investor Partners owning a majority of outstanding units at that time.

In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission, or SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2009 Form 10-K. The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2009 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three months ended March 31, 2010, 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.

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Index

PDC 2003-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

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

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

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

Internal Control over Financial Reporting in Exchange Act Periodic Reports

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

Note 3−Transactions with Managing General Partner and Affiliates

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

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Index

PDC 2003-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

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

	March 31, 2010			December 31, 2009

Natural gas and oil sales revenues collected from the Partnership’s third-party customers	$	243,149		$	207,355
Commodity price risk management, realized gains		188,396			226,559
Other (1)		(42,088	)		6,232
Total Due from Managing General Partner-other, net	$	389,457		$	440,146

(1)

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

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

	Three months ended March 31,
	2010		2009

Well operations and maintenance	$	290,760	$	240,974
Gathering, compression and processing fees		22,779		19,477
Direct costs - general and administrative		1,153		6,372
Cash distributions*		149,603		110,200

*Cash distributions include $13,058 during the three months ended March 31, 2010, and $8,545 during the three months ended March 31, 2009, related to equity cash distributions on Investor Partner units repurchased by PDC.

Note 4−Fair Value Measurements

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

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Index

PDC 2003-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

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


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

As of December 31, 2009
Assets:
Commodity based derivatives	$	311,686		$	328,947		$	640,633
Total assets		311,686			328,947			640,633

Liabilities:
Commodity based derivatives		(20,235	)		(78,306	)		(98,541	)
Basis protection derivative contracts		—			(1,105,795	)		(1,105,795	)
Total liabilities		(20,235	)		(1,184,101	)		(1,204,336	)

Net asset (liability)	$	291,451		$	(855,154	)	$	(563,703	)

As of March 31, 2010
Assets:
Commodity based derivatives	$	1,052,621		$	109,757		$	1,162,378
Total assets		1,052,621			109,757			1,162,378

Liabilities:
Commodity based derivatives		—			(75,243	)		(75,243	)
Basis protection derivative contracts		—			(1,244,179	)		(1,244,179	)
Total liabilities		—			(1,319,422	)		(1,319,422	)

Net asset (liability)	$	1,052,621		$	(1,209,665	)	$	(157,044	)

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


	Three months ended March 31, 2010
Fair value, net liability, as of December 31, 2009	$	(855,154	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		(86,605	)
Settlements		(267,906	)
Fair value, net liability, as of March 31, 2010	$	(1,209,665	)

Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2010 included in statement of operations line item:
Commodity price risk management, net	$	(106,572	)

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

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

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Index

PDC 2003-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 5−Derivative Financial Instruments

As of March 31, 2010, the Partnership had derivative instruments, comprised of commodity collars, commodity fixed-price swaps and a basis swap, in place for a portion of its anticipated production through 2013 for a total of 926,810 MMbtu of natural gas and 12,219 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

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

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

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	395,188		$	332,812

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		767,190			307,821

Total Derivative Assets			$	1,162,378		$	640,633

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(17,879	)	$	(20,800	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(336,102	)		(277,160	)

	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(57,364	)		(77,741	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(908,077	)		(828,635	)

Total Derivative Liabilities			$	(1,319,422	)	$	(1,204,336	)

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

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

	Three months ended March 31,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total

Commodity price risk management, net
Realized gains	$	247,949		$	19,957	$	267,906	$	419,614		$	86,584		$	506,198
Unrealized (losses) gains		(247,949	)		654,608		406,659		(419,614	)		(116,628	)		(536,242	)
Total commodity price risk management gain (loss), net	$	—		$	674,565	$	674,565	$	—		$	(30,044	)	$	(30,044	)

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

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Index

PDC 2003-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2010

(unaudited)

Note 6−Commitments and Contingencies

In December 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance region of Colorado. Operating expenses, including this fine, if any, are allocated among the users of the road based upon their respective usage. The Partnership has 13 wells in this region. The Notice alleged a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered into negotiations with the CDPHE regarding this notice and a settlement was accepted by CDPHE in November 2010. This settlement did not have a material impact on the Partnership’s financial position or results of operations.

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Index

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

PART I - FINANCIAL INFORMATION			Page No.
Item 1.1.	Financial Statements
		Balance Sheets - March 31, 2005 (unaudited) and December 31, 2004	1
		Statements of Operations - Three Months Ended March 31, 2005 and 2004 (unaudited)	2
		Statement of Partners' Equity and Comprehensive Income (Loss) - Three Months Ended March 31, 2005 (unaudited)	3
		Statements of Cash Flows- Three Months Ended March 31, 2005 and 2004 (unaudited)	4
		Notes to Financial Statements	5
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations	7
Item 3.		Quantitative and Qualitative Disclosure About Market Rate Risk	10
Item 4.		Controls and Procedures	11
PART II OTHER INFORMATION
Item 1.		Legal Proceedings	12
Item 6.		Exhibits	12

Partnership Overview

PDC 2003-D Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in December 2003 and operates 43 gross (41 net) productive wells located in the Rocky Mountain Region in the state of Colorado. The Partnership drilled two wells (1.5 net) that were evaluated to be developmental dry holes. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership’s results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

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

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

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

- 11 -

Index

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Balance~~The ~~Sheets~~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 to 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.

~~March~~Additional ~~31,~~Codell ~~2005~~Formation ~~and~~Development ~~December 31, 2004~~Plan

Assets
	2005	2004
	(Unaudited)
Current assets:
Cash	$ 3,118	1,380
Accounts receivable - oil and gas revenues	1,801,220	2,500,280
Due from managing general partner	1,162	-
Total current assets	1,805,500	2,501,660
Oil and gas properties, successful efforts method	38,078,510	38,078,510
Less accumulated depreciation, depletion
and amortization	5,081,970	4,088,138
	32,996,540	33,990,372
	$34,802,040	36,492,032
Liabilities and Partners' Equity
Current liabilities:
Accrued expenses	$ 284,883	218,689
Due to managing general partner	-	100
Total current liabilities	284,883	218,789
Asset retirement obligations	20,943	20,633
Partners' Equity	34,496,214	36,252,610
	$34,802,040	36,492,032

The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells which may provide for additional reserve development and natural gas production (the “Additional Codell Formation Development Plan”). The Additional Codell Formation Development Plan consists of the Partnership’s Wattenberg Field wells’ refracturing of wells currently producing in the Codell formation and the recompletion of wells, currently producing in the deeper J-Sand formation, in the shallower Codell formation production zone. Under the Additional Codell Formation Development Plan, the Partnership plans to initiate additional Codell formation development activities during 2011. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone.

~~See~~During ~~accompanying~~the ~~notes~~fourth quarter 2010, the Managing General Partner began withholding funds from several of the PDC sponsored partnerships, on a pro-rata basis allocated to ~~financial~~the ~~statements~~Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows resulting from current production. The funds retained are necessary for the Partnership to pay for additional Codell formation development costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not refractured or recompleted, the Partnership will experience a reduction in proved natural gas and oil reserves currently assigned to these wells. Both the number and timing of the additional Codell formation development activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing and recompletion costs and projected cash withholding, all Partnership additional Codell formation development activity will be completed within a five year period. This Partnership has not begun to withhold funds for this additional Codell formation development as this Partnership has outstanding payables to the General Partner.

~~-1-~~Current estimated costs for these well refracturings and recompletions are between $150,000 and $200,000 per activity. This Partnership potentially has 29 additional Codell formation development opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $4.4 million and $5.8 million. The Managing General Partner will continually evaluate the timing of commencing these additional Codell formation development activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development.

- 12 -

Index

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Statements~~Implementation of ~~Operations~~ the Additional Codell Formation Development Plan would reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in the future. Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Additional Codell Formation Development Plan. The above discussion is not intended as a substitute for careful tax planning, and third-party Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Additional Codell Formation Plan.

~~Three~~Partnership ~~Months~~Operating ~~ended~~Results ~~March 31, 2005 and 2004~~Overview

~~(Unaudited)~~Natural gas and oil sales increased 69% or $0.3 million for the first three months of 2010 compared to the first three months of 2009, even though production volumes moderately declined 3% period-to-period. The Partnership’s sales increase was driven primarily by the improved commodity price environment. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.62 for the current year period compared to $3.78 for the same period a year ago. Realized derivative gains from natural gas and oil sales contributed an additional $2.55 per Mcfe or $0.3 million to the first three months of 2010 total revenues. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased to $9.17 for the current year three months from $8.42 for the same prior year period.

	2005	2004	2002
Revenues:
Sales of oil and gas	$2,436,210	$171,546	633,245
	3,018	-	633,838
	2,439,228	171,546
Expenses:
Lifting cost	486,582	25,920	386,716
Direct administrative costs	332	74
Depreciation, depletion, and amortization	993,832 1,480,746	62,154 88,148	197,634
Net income	$ 958,482	$ 83,398	49,265
Net income per limited partner unit	$ 438	$ 46

- 13 -

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

-2-

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

~~Three~~The ~~months~~following ~~ended~~table ~~March~~presents ~~31,~~selected ~~2005~~information regarding the Partnership’s results of operations.

(Unaudited)


	Three months ended March 31,
	2010		2009		Change
Number of producing wells (end of period)		43		43		—

Production: (1)
Natural gas (Mcf)		82,795		86,295		-4	%
Oil (Bbl)		3,755		3,794		-1	%
Natural gas equivalents (Mcfe) (2)		105,325		109,059		-3	%
Mcfe per day		1,170		1,212

Natural Gas and Oil Sales
Natural gas	$	427,223	$	277,297		54	%
Oil		270,549		134,620		101	%
Total natural gas and oil sales	$	697,772	$	411,917		69	%

Realized Gain on Derivatives, net
Natural gas	$	235,181	$	384,149		-39	%
Oil		32,725		122,049		-73	%
Total realized gain on derivatives, net	$	267,906	$	506,198		-47	%

Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	5.16	$	3.21		61	%
Oil (per Bbl)		72.05		35.48		103	%
Natural gas equivalents (per Mcfe)		6.62		3.78		75	%

Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	8.00	$	7.66		4	%
Oil (per Bbl)		80.77		67.65		19	%
Natural gas equivalents (per Mcfe)		9.17		8.42		9	%

Average Lifting Cost (per Mcfe) (3)	$	3.12	$	2.62		19	%

Operating costs and expenses:
Direct costs - general and administrative	$	1,153	$	6,372		-82	%
Depreciation, depletion and amortization	$	445,120	$	500,354		-11	%

Cash distributions	$	682,728	$	508,271		34	%

	Limited and Additional General Partners	Managing General Partner	Accumulated Other Comprehensive Income (loss)	Total
Balance December 31, 2004	$29,091,805	7,272,954	(112,149)	36,252,610
Distributions to partners	(2,060,875)	(515,218)	-	(2,576,093)
Comprehensive income:
Net income	766,786	191,696	-	958,482
Change in fair value of outstanding hedging positions			(149,530)
Less reclassification adjustments for settled contracts included in net income			10,745
Other comprehensive loss			(138,785)	(138,785)
Comprehensive income				819,697
Balance March 31, 2005	$ 27,797,716	6,949,432	(250,934)	34,496,214

(1)

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

~~See~~(2) ~~accompanying~~A ~~notes~~ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to ~~financial~~obtain ~~statements~~a conversion factor to convert oil production into equivalent Mcf of natural gas.

-(3-) Lifting costs represent natural gas and oil operating expenses, which include production taxes.

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

●

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

●

MBbl – One thousand barrels

●

Mcf – One thousand cubic feet

●

MMcf – One million cubic feet

●

Mcfe – One thousand cubic feet of natural gas equivalents

●

MMcfe – One million cubic feet of natural gas equivalents

●

MMbtu – One million British Thermal Units

- 14 -

Index

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Three ~~Months~~months ended March 31, ~~2005~~2010 ~~and~~as ~~2004~~compared to three months ended March 31, 2009

~~(Unaudited)~~The $0.3 million, or 69% increase in total sales for the 2010 three month period as compared to the same period in 2009, was primarily a reflection of an increase in the significantly higher average sales price per Mcfe, of 75% that was partially offset by the moderate reduction of Partnership production volumes of 3% during the comparable period. Average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.62 for the current year quarter compared to $3.78 for the same quarter a year ago.

	2005	2004
Cash flows from operating activities:
Net income	$958,482	83,398
Adjustments to reconcile net income to net cash
provided from (used by) operating activities:
Depreciation, depletion and amortization	993,832	62,154
Accretion of asset retirement obligation	310	-
Changes in operating assets and liabilities: Decrease (increase) in accounts receivable - oil and gas revenues	632,880	(145,626)
Increase in from managing general partner	(1,262)	-
Decrease in accounts payable	(6,411)	-
Net cash provided from (used by) operating activities	2,577,831	(74)
Cash flows from financing activities:
Distributions to partners	(2,576,093)	-
Net cash used by financing activities	(2,576,093)	-
Net increase (decrease) in cash	1,738	(74)
Cash at beginning of period	1,380	90
Cash at end of period	$ 3,118	16

Oil revenue increases of 101% were significantly above natural gas revenue increases of 54% for the 2010 three month period compared to the same period last year. The Partnership’s oil revenue increase was bolstered by improved average oil sales prices per Bbl, of 103% as compared to the more moderate, yet significant, increase in natural gas sales prices per Mcf, of 61% during the period.

~~See~~The ~~accompanying~~Partnership ~~notes~~expects to ~~financial~~experience ~~statements~~declines in both natural gas and oil production volumes over the wells’ life cycles until such time that the Partnership’s Codell formation Wattenberg Field wells are successfully recompleted. Subsequent to this additional Codell formation development, production will once again be expected to decline.

~~-4-~~Natural Gas and Oil Pricing

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

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices. The CIG Index, and other indices for production delivered to Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in the year and is lower than historical variances. This negative differential between NYMEX and CIG averaged $1.62 for the three months ended March 31, 2009, and narrowed to an average of $0.16 for the three months ended March 31, 2010.

Commodity Price Risk Management, Net

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

- 15 -

Index

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Notes~~The tofollowing ~~Financial Statements~~table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain (loss), net.

(Unaudited)

	Three months ended March 31,
	2010			2009
Commodity price risk management, net
Realized gain
Oil	$	32,725		$	122,049
Natural Gas		235,181			384,149
Total realized gain, net		267,906			506,198

Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(247,949	)		(419,614	)
Unrealized gain (loss) for the period		654,608			(116,628	)
Total unrealized gain (loss), net		406,659			(536,242	)
Commodity price risk management gain (loss), net	$	674,565		$	(30,044	)

~~1. Accounting Policies~~Three months ended March 31, 2010 as compared to three months ended March 31, 2009

~~Reference~~The isrealized ~~hereby made~~derivative togains ~~PDC~~for ~~2003-D~~the ~~Limited~~2010 ~~Partnership's~~first (quarter were $0.3 million as a result of lower natural gas and oil spot prices at the ~~Partnership's)~~settlement ~~Annual~~date ~~Report~~compared ~~on Form~~to ~~10-K~~the respective strike price. Unrealized gains for ~~2004,~~the ~~which~~2010 ~~contains~~first quarter of $0.7 million were due primarily to a ~~summary~~downward ofshift ~~significant~~in ~~accounting~~the ~~policies followed~~natural gas and oil forward curves, offset by unrealized losses due to the ~~Partnership~~basis indifferential between NYMEX and CIG being narrower than the ~~preparation~~strike price of ~~its~~the ~~financial~~derivative ~~statements~~position. ~~These~~ Unrealized ~~policies~~gains on the Partnership’s commodity positions for the 2010 first quarter were ~~also~~$0.8 ~~followed~~million inpartially ~~preparing~~offset by unrealized losses on the ~~quarterly~~Partnership’s ~~report~~basis ~~included herein~~position of $0.1 million.

2During the first quarter of 2009, the Partnership experienced realized gains and unrealized derivative losses as natural gas and oil prices declined. ~~Basis~~ The net unrealized loss for the first quarter of ~~Presentation~~2009 was comprised of a decrease in fair value of the Partnership’s basis position which resulted from a steeper decline in NYMEX pricing relative to CIG pricing that was partially offset by an unrealized gain from the Partnership’s commodity derivatives.

Natural Gas and Oil Sales Derivative Instruments. The ~~Management~~ Managing General Partner on behalf of the Partnership ~~believes~~in ~~that~~accordance ~~all~~with ~~adjustments~~the ~~(consisting~~D&O ofAgreement, ~~only normal~~is ~~recurring~~authorized ~~accruals)~~to ~~necessary~~utilize tovarious aderivative ~~fair~~instruments ~~statement~~to ofmanage ~~the~~volatility ~~results~~in ofnatural ~~such periods~~gas ~~have~~and ~~been~~oil ~~made~~prices. The ~~results~~Partnership ofhas ~~operations~~in ~~for~~place ~~the~~a ~~three~~series ~~months~~of ~~ended~~collars, ~~March~~fixed-price ~~31,~~swaps ~~2005~~and ~~are~~a ~~not~~basis ~~necessarily~~swap ~~indicative~~on a portion of the ~~results~~Partnership’s natural gas and oil production. See Note 5, Derivative Financial Instruments to bethe ~~expected~~Partnership’s financial statements included in the 2009 Form 10-K for an additional discussion on how each derivative type impacts the ~~full year.~~Partnership’s cash flows.

~~3. Oil and~~- ~~Gas~~16 ~~Properties~~-

The Partnership follows the successful efforts method of accounting for the cost of exploring for and developing oil and gas reserves. Under this method, costs of development wells, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, and successful exploratory wells are capitalized and amortized on an annual basis to operations by the units-of-production method using estimated proved developed reserves determined at year end by an independent petroleum engineer, Wright & Company, Inc. If a determination is made that an exploratory well has not discovered economically producible reserves, then its costs are expensed as dry hole cost. Index

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

4. Revenue Recognition

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

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

-5-

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Notes~~The tofollowing ~~Financial Statements~~table presents the Partnership’s derivative positions in effect as of March 31, 2010.

(Unaudited)


	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
			Weighted Average				Quantity		Weighted Average				Weighted Average			Fair Value at
Commodity/	Quantity		Contract Price				(Gas-Mmbtu(1)		Contract		Quantity		Contract			March 31,
Index	(Gas-Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Price		(Gas-Mmbtu(1))		Price			2010(2)

Natural Gas
CIG
10/01 - 12/31/2010		21,228	$	4.75	$	9.45		—	$	—		—	$	—		$	13,783
01/01 - 03/31/2011		31,842		4.75		9.45		—		—		—		—			15,107

NYMEX
04/01 - 06/30/2010		—		—		—		65,469		5.56		72,197		(1.88	)		89
07/01 - 09/30/2010		—		—		—		64,815		5.56		71,323		(1.88	)		(16,397	)
10/01 - 12/31/2010		6,523		5.75		8.30		40,041		6.15		48,862		(1.88	)		(2,866	)
01/01 - 03/31/2011		8,868		5.75		8.30		25,208		6.83		34,076		(1.88	)		(6,793	)
04/01 - 12/31/2011		—		—		—		195,100		6.77		195,100		(1.88	)		(3,383	)
2012-2013		14,905		6.00		8.27		452,811		7.05		467,715		(1.88	)		(137,504	)
Total Natural Gas		83,366						843,444				889,273					(137,964	)

Oil
NYMEX
04/01 - 06/30/2010		—		—		—		2,336		92.96		—		—			20,192
07/01 - 09/30/2010		—		—		—		2,362		92.96		—		—			18,540
10/01 - 12/31/2010		—		—		—		2,362		92.96		—		—			17,432
01/01 - 03/31/2011		—		—		—		1,248		70.75		—		—			(17,880	)
04/01 - 12/31/2011		—		—		—		3,911		70.75		—		—			(57,364	)
Total Oil		—						12,219				—					(19,080	)

Total Natural Gas and Oil																$	(157,044	)

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

~~5. Derivative~~(2) ~~Instruments~~Approximately 9% of the fair value of the Partnership’s derivative assets and ~~Hedging~~all ~~Activities~~of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.

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

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

~~Changes~~Three inmonths ~~fair value~~ended ofMarch ~~a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in accumulated other comprehensive income~~31, ~~until~~2010 earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Partnership discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is designated as acompared ~~hedging~~to ~~instrument,~~three ~~because~~months itended isMarch ~~probable that a forecasted transaction will not occur~~31, ~~or the Partnership determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will be discontinued.~~2009

ByFor ~~using~~the ~~derivative~~2010 ~~financial~~three ~~instruments to~~month ~~hedge~~period ~~exposures~~compared to ~~changes~~2009 inthree ~~commodity~~month ~~prices~~period, ~~the~~oil ~~Managing~~and ~~General~~natural ~~Partner exposes~~production, ~~the~~on ~~Partnership~~an toenergy ~~credit~~equivalency-basis, ~~risk.~~decreased ~~Credit~~moderately ~~risk~~by is3,734 ~~the~~Mcfe, ~~failure~~or of3% ~~the counterparty~~due to ~~perform~~normal ~~under~~production ~~the~~declines ~~terms~~for ofthis stage in the ~~derivative~~wells’ ~~contract~~production life cycle. Production ~~When~~and operating costs, excluding the ~~fair~~ ~~value~~effect of a ~~derivative~~prior ~~contract~~year isaccrued ~~positive~~production tax downward revision, increased by approximately $0.1 million for the ~~counterparty~~2010 ~~owes~~first quarter compared to the ~~Partnership~~ prior year first quarter due primarily to environmental remediation expenditures at one Wattenberg Field well location. This increase in lease operating expenditures was partially offset by the downward adjustment to accrued production taxes due to the Colorado tax agency’s production tax rate revisions, which ~~creates~~was ~~credit~~publically ~~risk~~announced by the agency during the first quarter 2010. Production ~~The~~and ~~Managing~~operating ~~General~~costs ~~Partner~~per ~~minimizes~~ Mcfe were $3.12 for the ~~credit~~2010 ~~risk~~three inmonth ~~derivative~~period ~~instruments~~compared byto ~~entering~~$2.62 ~~into~~for ~~transactions~~the ~~with high-quality~~comparable ~~counterparties~~2009 three month period.

-6 17 -

Index

PDC 2003-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Notes~~Depreciation, toDepletion ~~Financial Statements~~and Amortization

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

~~Item 2. Management's~~Three ~~Discussion~~months ~~and~~ended ~~Analysis~~March of31, ~~Financial~~2010 ~~Condition~~as ~~and Results~~compared ofto ~~Operations~~three months ended March 31, 2009

~~Liquidity~~ The Partnership’s DD&A expense decreased approximately $0.1 million during the 2010 first quarter compared to the prior year quarter. The DD&A expense reduction was the result of the combined effects of lower DD&A expense rates per Mcfe of $4.23 during the current year quarter compared to $4.59 during the prior year quarter and ~~Capital~~moderately ~~Resources~~lower production volumes, noted in previous sections. The DD&A rate decrease was due to the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates, in addition to the effect of the upward revision in the Partnership’s Wattenberg Field’s proved developed producing natural gas and oil reserves, as calculated by the respective methodologies described above.

~~The~~Capital ~~Partnership~~Resources ~~was funded on December 15, 2003 with initial Limited~~ and Additional General Partner contributions of $34,996,823 (1,749.84 units) and the Managing General Partner's cash contribution of $7,611,809 in accordance with the Limited Partnership Agreement. After payment of syndication costs of $3,674,666 and a one-time management fee to the Managing General Partner of $874,921 the Partnership had available cash of $38,059,045 for Partnership activities.Liquidity

The Partnership ~~began~~’s ~~exploration~~primary ~~and~~sources ~~development~~of cash for the three months ended March 31, 2010 were from funds provided by operating activities ~~subsequent~~which toinclude the ~~funding~~sale of natural gas and oil production and the realized gains from the Partnership’s ~~and~~derivative ~~completed~~positions. These ~~well~~sources ~~drilling~~of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by ~~March~~changes 31in commodity prices, ~~2004~~in production volumes and in realized gains and losses from commodity positions. ~~Forty-three~~ Commodity ~~wells~~prices have historically been ~~drilled~~volatile and the Partnership attempts to manage this volatility through derivatives. Therefore, the primary source of ~~which~~the ~~forty-two~~Partnership’s ~~have~~cash ~~been~~flow ~~completed~~from as operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold economic hedges for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. No As ~~additional~~of ~~wells~~March ~~will~~31, be2010, ~~drilled~~the Partnership had natural gas and oil derivative positions in place covering substantially all of the expected natural gas and oil production for the remainder of 2010, at an average price of $3.77 per Mcf and $92.96 per Bbl, respectively. The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2009 comparative period, which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

~~The Partnership~~- ~~had~~18 ~~net working capital at March 31, 2005 of $1,520,617.~~-

~~Operations are expected to be conducted with available funds and revenues generated from oil and gas activities. No bank borrowings are anticipated.~~ Index

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

~~Three~~(A ~~months~~West ~~ended~~Virginia ~~March~~Limited ~~31, 2005 compared with March 31, 2004~~Partnership)

~~Oil and~~The ~~gas~~Partnership’s ~~sales~~future ~~for~~operations ~~the~~are ~~three~~expected ~~months~~to ~~ended~~be ~~March~~conducted ~~31,~~with ~~2005~~available ~~were~~funds ~~$2,436,210~~and ~~compared~~revenues togenerated ~~$171,546~~from ~~for~~natural ~~the~~gas ~~three~~and ~~months~~oil ~~ended~~production ~~March~~activities ~~31,~~and ~~2004. For~~commodity ~~the~~gains, ~~three~~if ~~months~~any. Natural ~~ended~~gas ~~March~~and ~~31,~~oil ~~2005,~~production from the Partnership’s ~~sold~~existing ~~356,519~~properties ~~Mcf~~are ofgenerally ~~gas~~expected ~~and~~to ~~10,925 barrels~~continue ofa ~~oil~~gradual atdecline ~~average~~in ~~sales~~the ~~prices~~rate of ~~$5.43~~production ~~and~~over ~~$45~~the remaining lives of the wells.91 Therefore, ~~respectively.~~the ~~This compared~~Partnership ~~with~~anticipates ~~11,943~~a ~~Mcf~~lower annual level of natural gas and 3oil production and,~~189~~ ~~barrels~~in the absence of ~~oil~~significant atprice ~~average~~increases ~~sales~~or ~~prices of~~successful ~~$5.16~~additional ~~and~~Codell ~~$34.47~~formation development, ~~respectively~~lower ~~for~~revenues. The ~~the~~Partnership ~~three~~also ~~months~~expects ~~ended~~cash ~~March~~flows ~~31,~~from ~~2004. Lifting~~operations ~~cost~~to ~~per~~decline ~~Mcfe~~if ~~for~~commodity ~~the~~prices ~~three~~remain ~~months~~at ~~ended~~current ~~March~~levels ~~31,~~or ~~2005~~decrease ~~amounted~~in tothe $1future.15 Under asthese ~~compared~~circumstances todecreased ~~$.83~~production ~~per~~would ~~Mcfe~~have ~~for~~a ~~the~~material ~~three~~negative ~~months~~impact ~~ended~~on ~~March~~the ~~31,~~Partnership’s ~~2004. This~~operations ~~increase~~and ismay ~~partially~~result ~~attributed~~in reduced cash distributions to the ~~increase~~Managing inGeneral ~~severance~~Partner ~~tax~~ and ~~property taxes~~Investor onPartners ~~higher~~through ~~average~~the ~~sales~~remainder ~~prices~~ of ~~natural~~2010 ~~gas~~and beyond, and ~~oil~~may ~~sold. Cash distributions~~substantially toreduce or restrict the ~~partners~~Partnership’s ~~amounted~~ability to ~~$2,576,093~~participate ~~for~~in the ~~three~~refracturing ~~months~~and ~~ended~~ recompletion ~~March~~activities 31which are more fully described in Item 2, ~~2005. In~~Management’s ~~2004~~Discussion ~~cash~~and ~~distributions~~Analysis ~~commenced~~of inFinancial ~~the~~Condition ~~second~~and ~~quarter~~Results of Operations−Additional Codell Formation Development Plan.

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

~~Critical Accounting~~Working ~~Policies~~capital at March 31, 2010 was $0.7 million compared to working capital of $0.8 million at December 31, 2009, a decrease of approximately $0.1 million. This decrease was primarily due to the following changes in accounts receivable and payable balances:

~~Certain~~● ~~accounting~~Natural ~~policies~~gas ~~are very important to the portrayal of the Partnership's financial condition~~ and ~~results~~oil ~~of operations~~receivables ~~and~~remained ~~require~~substantially ~~management's~~unchanged ~~most~~at ~~subjective or complex judgments~~$0. ~~In applying~~4 ~~those~~million ~~policies,~~as ~~our management uses its judgment to determine the appropriate assumptions to be used in the determination~~ of ~~certain~~March ~~estimates. Those estimates are based on our historical experience~~31, ~~our~~2010 ~~observance~~and ~~of trends~~December ~~in the industry~~31, ~~and information available from other outside sources~~2009, as ~~appropriate~~respectively. ~~The Partnership's critical accounting policies and estimates are as follows:~~

~~-7-~~● Realized derivative gains receivables remained substantially unchanged at $0.2 million as of March 31, 2010 and December 31, 2009, respectively.

~~PDC~~● ~~2003~~Due to the Managing General Partner-Dother ~~LIMITED PARTNERSHIP~~payable, excluding natural gas and oil sales received from third parties and realized derivative gains, increased by approximately $0.1 million as of March 31, 2010, compared to December 31, 2009.

(AWorking ~~West~~capital, ~~Virginia Limited~~primarily cash and cash equivalents, is expected to increase during early 2011 due to the Partnership)’s anticipated withholding cash from the Managing General Partner and Investor Partners, on a pro-rata basis, for the initial additional Codell formation development activities. This withholding is expected to begin in fourth quarter 2010. Cash will begin to decrease as the funds are utilized in payment of the completed development activities, currently planned to occur during mid-to-late 2011. Funding for the Additional Codell Formation Development Plan will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners on a pro-rata basis. Working capital is expected to similarly fluctuate by increasing during periods of Additional Codell Formation Development Plan funding and by decreasing during periods when payments are made for completed refracturing or recompletion.

~~Notes~~Cash ~~to Financial Statements~~Flows

~~(Unaudited)~~Cash Flows From Investing Activities

~~Revenue~~The ~~Recognition. Sales of~~Partnership, ~~natural~~from ~~gas are recognized when natural gas has been delivered~~ time-to ~~a custody transfer point~~-time, ~~persuasive~~invests ~~evidence~~in ofadditional aequipment ~~sales~~which ~~arrangement~~supports ~~exists~~treatment, ~~the~~delivery ~~rights~~ and ~~responsibility~~measurement of ~~ownership~~natural ~~pass~~gas ~~to the purchaser upon delivery, collection of revenue from the sale is reasonably assured~~ and ~~the~~oil ~~sales price is fixed~~ or ~~determinable. Natural~~ ~~gas~~environmental ~~is sold by the Managing General Partner under contracts with terms ranging from one month to three years~~protection. ~~Virtually~~ These ~~all~~amounts ~~of the~~totaled ~~Managing~~approximately ~~General Partner's contracts pricing provisions are tied to a market index~~$2,000 ~~with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas~~ and ~~prevailing~~ ~~supply and demand conditions~~$66,000 sofor ~~that~~ the ~~price~~three ofmonths ~~the~~ended ~~natural~~March ~~gas fluctuates to remain competitive with other available natural gas supplies. As a result~~31, ~~the~~2010 ~~Partnership's revenues from the sale of natural gas will suffer if market prices decline~~ and ~~benefit~~2009, ~~if they increase~~respectively. ~~The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.~~

~~The Managing General Partner currently uses the "Net~~-~~Back"~~ ~~method~~19 of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner's customers and reflected in the wellhead price.-

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

~~Impairment~~PDC ~~of Long~~2003-~~Lived~~D ~~Assets.~~LIMITED The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.PARTNERSHIP

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

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

The Partnership ~~assesses~~initiated ~~impairment~~monthly ofcash ~~capitalized~~distributions ~~costs of proved oil and gas properties by comparing net capitalized costs~~ to ~~estimated undiscounted~~investors ~~future~~in ~~cash~~July ~~flows~~2004 onand ahas ~~field-by-field~~distributed ~~basis using expected prices~~$29. ~~Prices~~4 ~~utilized~~million inthrough ~~each~~March ~~year's~~31, ~~calculation~~2010. The ~~for~~table ~~measurement~~below ~~purposes~~presents ~~and expected costs are held constant throughout~~ the ~~estimated~~cash ~~life~~distributions ofto the ~~properties.~~ IfManaging ~~net~~General ~~capitalized~~Partner ~~costs~~and ~~exceed~~Investor ~~undiscounted future net cash flow~~Partners, ~~the~~ ~~measurement~~including ofManaging ~~impairment~~General isPartner ~~based~~distributions onrelating ~~estimated~~to ~~fair~~limited ~~value~~partnership ~~which~~units ~~would consider~~repurchased, ~~future~~for ~~discounted~~the ~~cash~~periods ~~flows~~described.

Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes are capitalized.

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

2010	$	136,545	$	546,183	$	682,728

2009	$	101,655	$	406,616	$	508,271

~~Unproved~~Cash ~~properties~~Flows ~~and~~From ~~leases~~Operating ~~are written-off to expense when it is determined that they will expire to be abandoned.~~Activities

~~Costs~~Net ofcash ~~proved~~provided ~~properties,~~by ~~including~~operating ~~leasehold acquisitions,~~activities ~~exploration~~was ~~and~~$0.7 ~~development~~million ~~costs~~for ~~and~~the ~~equipment~~three months ended March 31, ~~are~~2010, ~~depreciated and~~compared ~~depleted~~to by$0.6 million for the ~~unit-of-production~~comparable ~~method~~period ~~based~~in on2009. The ~~estimated~~$0.1 ~~proved developed~~million ~~oil~~increase ~~and~~in ~~gas~~cash ~~reserves.~~provided by operating activities was due primarily to the following:

~~-8-~~● An increase in natural gas and oil sales receipts of $0.1 million,

~~PDC~~● ~~2003-D~~A ~~LIMITED PARTNERSHIP~~decrease in commodity price risk management realized gains receipts of approximately $0.1 million or 26% and

(A● ~~West~~An ~~Virginia Limited~~increase ~~Partnership)~~in Due to Managing General Partner-other, net, receipts of $0.1 million, excluding natural gas and oil sales received from third parties and realized derivative gains.

~~Notes~~Commitments toand ~~Financial Statements~~Contingencies

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

~~Upon~~Recent ~~sale~~Accounting or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value, is credited or charged to income. Upon sale of a partial unit of property, the proceeds are credited to accumulated depreciation and depletion.Standards

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

~~Asset Retirement~~Critical ~~Obligations~~Accounting Policies and Estimates

On The ~~March~~preparation ~~30,~~of ~~2005,~~ the ~~FASB~~accompanying ~~issued~~unaudited ~~FASB~~condensed ~~Interpretation~~financial ~~No.~~statements ~~47,~~in ~~"Accounting~~conformity ~~for Conditional~~with ~~Asset Retirement Obligations" (FIN No~~U. ~~47)~~S. ~~This~~ ~~interpretation clarifies~~GAAP ~~that~~requires ~~the~~management ~~term "conditional asset retirement obligation" as used in Statement No. 143 refers~~ to ause ~~legal~~judgment ~~obligation to perform an asset retirement activity~~ in ~~which~~making ~~the~~estimates ~~timing~~ and~~/or~~ ~~method~~assumptions ~~of settlement are conditional on a future event~~ that ~~may~~affect ~~or may not be within~~ the ~~control~~reported ofamounts ~~the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method~~ of ~~settlement. Thus,~~ ~~the~~assets ~~timing~~ and~~/or~~ ~~method of settlement may be conditional on a future event. Accordingly~~liabilities, andisclosure ~~entity is required to recognize a liability for the fair value~~ of acontingent ~~conditional~~assets ~~asset~~and ~~retirement~~liabilities ~~obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing~~ and~~/or~~ ~~method of settlement of a conditional asset retirement obligation should be factored into~~ the ~~measurement~~reported ofamounts ~~the liability, rather than the timing~~ of ~~recognition~~revenue ofand ~~the liability, when sufficient information exists~~expenses. FIN No. 47 will be effective for the Partnership at the end of the fiscal year ended December 31, 2005. The Partnership has not determined the impact on the Partnership's financial position or results of operations of the application of FIN No. 47.

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

~~This Form 10~~-Q ~~contains~~20 ~~"forward~~-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are the Managing General Partner's estimate of the sufficiency of its existing capital sources, its ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Partnership has filed with the Securities and Exchange Commission. The Partnership undertakes no duty to update or revise these forward-looking statements.

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

PDC 2003-9-D LIMITED PARTNERSHIP

~~PDC~~(A ~~2003-D~~West ~~LIMITED PARTNERSHIP~~Virginia Limited Partnership)

(AOff-Balance ~~West~~Sheet ~~Virginia Limited Partnership)~~Arrangements

~~Notes~~Currently, tothe ~~Financial Statements~~Partnership does not have any off-balance sheet arrangements.

~~(Unaudited)~~Item 3. Quantitative and Qualitative Disclosures About Market Risk

~~Item~~Not 3applicable. ~~Quantitative and Qualitative Disclosure About Market Rate Risk~~

~~Market-Sensitive~~Item ~~Instruments~~4. Controls and ~~Risk Management~~Procedures

The Partnership's ~~primary~~has ~~market~~no ~~risk~~direct ~~exposure~~management isor ~~commodity~~officers. The ~~price~~management, ~~risk. This exposure~~officers isand ~~discussed~~other inemployees ~~detail~~that ~~below:~~provide services on behalf of the Partnership are employed by the Managing General Partner.

~~Commodity~~(a) ~~Price~~Evaluation ~~Risk~~of Disclosure Controls and Procedures

~~The~~As ~~Managing~~of ~~General~~March ~~Partner~~31, ~~utilizes~~2010, ~~commodity-based derivative~~PDC, ~~instruments~~ as ~~hedges~~Managing toGeneral ~~manage~~Partner aof ~~portion~~the ofPartnership, ~~its~~carried ~~exposure~~out toan ~~price risk~~evaluation ~~from~~under ~~its~~the ~~oil~~supervision and ~~natural~~with ~~gas~~the ~~sales. These~~participation ~~instruments consist~~ of ~~CIG (Colorado~~the ~~Interstate~~Managing ~~Gas~~General ~~index)~~Partner’s -management, ~~based~~including ~~contracts~~the ~~for~~Chief ~~natural~~Executive ~~gas~~Officer ~~futures~~ and ~~option~~ ~~contracts~~the ~~for~~Chief ~~gas~~Financial ~~production~~Officer, ~~and~~of ~~NYMEX~~the ~~traded~~effectiveness ~~oil~~of ~~futures~~the design and ~~option contracts~~operation ~~for~~of ~~oil~~the ~~production. These~~Partnership’s ~~hedging~~disclosure ~~arrangements~~controls ~~have~~and ~~the~~procedures ~~effect~~pursuant ~~of locking~~to inSecurities ~~for~~Exchange ~~specified~~Act ~~periods~~Rule 13a-15(ate) ~~predetermined~~and ~~prices~~15d-15(e). This orevaluation ~~ranges~~considered ofthe ~~prices)~~ various processes carried out under the ~~prices~~direction of the Managing General Partner’s ~~will~~Disclosure ~~receive~~Committee ~~for~~in ~~the~~an ~~volume~~effort to ~~which the~~ensure ~~hedge~~that ~~relates. As~~information arequired ~~result,~~to ~~while~~be ~~these~~disclosed ~~hedging~~in ~~arrangements~~the ~~are structured~~SEC toreports ~~reduce~~that ~~the~~we ~~Partnership's~~file ~~exposure~~or tosubmit ~~changes~~under inthe ~~price~~Exchange ~~associated with~~Act ~~the~~are ~~hedged~~recorded, ~~commodity~~processed, ~~they~~summarized ~~also~~and ~~limit~~reported within the ~~benefit~~time periods specified by the ~~Partnership~~SEC’s ~~might otherwise~~rules ~~have~~and ~~received~~forms, ~~from~~and ~~price~~that ~~changes~~such ~~associated~~information ~~with~~is ~~the~~accumulated ~~hedged commodity.~~and ~~The~~communicated to the Partnership'’s ~~policy~~management, ~~prohibits~~including the ~~use~~Chief ofExecutive ~~oil~~Officer and ~~natural~~Chief ~~gas~~Financial ~~future and~~Officer, ~~option~~as ~~contracts~~appropriate, ~~for~~to ~~speculative~~allow ~~purposes~~timely discussion regarding required financial disclosure.

~~The~~Based ~~following~~on ~~tables~~the ~~summarize~~results of this evaluation, the ~~open~~Managing ~~futures~~General Partner’s Chief Executive Officer and ~~options~~ ~~contracts~~the ~~for~~Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of March 31, ~~2005 and 2004~~2010.

~~Commodity~~(b) ~~Type~~Changes ~~Quantity~~in ~~Gas-Mmbtu~~Internal ~~Oil-Barrels~~Control ~~Weighted~~over ~~Average~~Financial ~~Price Total Contract Amount Fair Market Value~~Reporting

~~Total~~PDC, ~~Contracts~~the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended March 31, ~~2005~~2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

Natural Gas	Floors	376,429	4.19	-	10,030
Natural Gas	Ceilings	188,214	6.69	-	(206,834)
Oil	Floors	6,549	32.30	211,534	211
Oil	Ceilings	3,275	40.00	130,981	(54,341)

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~~Contracts maturing in 12 months following March 31, 2005~~Index

Natural Gas	Floors	276,238	4.07	-	4,069
Natural Gas	Ceilings	138,119	6.48	-	(186,583)
Oil	Floors	6,549	32.30	211,534	211
Oil	Ceilings	3,275	40.00	130,981	(54,341)

PDC 2003-D LIMITED PARTNERSHIP

~~Prior~~(A ~~Year~~West ~~Total~~Virginia ~~Contracts~~Limited ~~as of March 31, 2004~~Partnership)

Natural Gas	Floors	-	-	-	-
Natural Gas	Ceilings	-	-	-	-
Oil	Sales	4,321	31.63	136,685	(5,680)

PART II – OTHER INFORMATION

~~The~~Item ~~maximum~~1. ~~term~~Legal ~~over which the Partnership is hedging exposure to the variability of cash flows for commodity price risk is 19 months.~~ Proceedings

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

AsItem ~~the information above incorporates only those exposures that exist at March 31, 2005, it does not consider those exposures or positions which could arise after that date~~1A. AsRisk a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.Factors

~~-10-~~Not applicable.

~~PDC~~Item ~~2003-D~~2. ~~LIMITED PARTNERSHIP~~Unregistered Sales of Equity Securities and Use of Proceeds

(AUnit ~~West~~Repurchase ~~Virginia Limited~~Program: Beginning July 2007, the third anniversary of the date of the first Partnership) cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units. There were no units repurchased during the three months ended March 31, 2010.

~~Notes~~Item to3. ~~Financial Statements~~Defaults Upon Senior Securities

~~(Unaudited)~~Not applicable.

Item 4. ~~Controls~~ [Removed and ~~Procedures~~Reserved]

~~Under~~Item the supervision and with the participation of the Managing General Partner's management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, the Managing General Partner has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of this fiscal quarter, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Managing General Partner's Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure5. ~~There~~Other have been no significant changes in our internal control over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect these controls that occurred during the Partnership's last fiscal quarter and subsequent to the date of their evaluation.Information

~~-11-~~Not applicable.

~~CONFORMED~~- ~~COPY~~22 -

~~PART II - OTHER INFORMATION~~Index

~~Item 1. Legal~~PDC ~~Proceedings~~2003-D LIMITED PARTNERSHIP

~~None.~~(A West Virginia Limited Partnership)

Item 6. Exhibits

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

(a) Exhibit Index.

SIGNATURES

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

3.1

Limited Partnership Agreement

10-K

000-50618

3.1

10/12/2010

3.2

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

10-K

000-50618

3.2

10/12/2010

10.1

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

10-K

000-50618

10.1

10/12/2010

31.1

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

31.2

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

32.1

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

~~Pursuant~~- to23 ~~the requirements of the Securities Exchange Act of 1934 the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.~~-

	PDC 2003-D Limited Partnership (Registrant) By its Managing General Partner Petroleum Development Corporation
Date: May 13, 2005	/s/ Steven R. Williams Steven R. Williams Chairman
Date: May 13, 2005	/s/ Darwin L. Stump Darwin L. Stump Chief Financial Officer

Index

PDC 2003-~~12-~~D 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-D Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

of Petroleum Development Corporation (dba PDC Energy)

December 15, 2010

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	Date

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

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

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

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Filing Compare · PDC 2003-D LP