UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

Tx QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September~~March 3031, ~~2010~~2011

£o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-50226

PDC 2002-D Limited Partnership

(Exact name of registrant as specified in its charter)


West Virginia		04-3726919
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

(303) 860-5800

(Registrant's telephone number, including area code)

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

Yes £ No T

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

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

Large accelerated filer £¨ Accelerated filer £¨ Non-accelerated filer £¨ Smaller reporting company Tþ

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

As of ~~September~~March 3031, ~~2010~~2011 the Partnership had 1,455.26 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		~~Page~~	Page
~~PART I – FINANCIAL INFORMATION~~		PART I – FINANCIAL INFORMATION
	Note Regarding Forward-Looking Statements	1
		Special Note Regarding Forward-Looking Statements	1
Item 1.	~~Financial Statements (unaudited)~~	Financial Statements (unaudited)
	~~Condensed Balance Sheets (unaudited)~~	2Condensed Balance Sheets (unaudited)	3
	~~Condensed Statements of Operations (unaudited)~~	3Condensed Statements of Operations (unaudited)	4
	~~Condensed Statements of Cash Flows (unaudited)~~	4Condensed Statements of Cash Flows (unaudited)	5
	~~Notes to Unaudited Condensed Financial Statements~~	5Notes to Unaudited Condensed Financial Statements	6
Item 2.	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~	11Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	~~Quantitative and Qualitative Disclosures About Market Risk~~	22Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	~~Controls and Procedures~~	22Controls and Procedures	21
~~PART II – OTHER INFORMATION~~		PART II – OTHER INFORMATION
Item 1.	~~Legal Proceedings~~	23Legal Proceedings	23
Item 1A.	~~Risk Factors~~	23Risk Factors	23
Item 2.	~~Unregistered Sales of Equity Securities and Use of Proceeds~~	23Unregistered Sales of Equity Securities and Use of Proceeds	23
Item 3.	~~Defaults Upon Senior Securities~~	23Defaults Upon Senior Securities	23
Item 4.	~~[Removed and Reserved]~~	23[Removed and Reserved]	23
Item 5.	~~Other Information~~	23Other Information	23
Item 6.	~~Exhibits~~	24Exhibits Index	24
	~~SIGNATURES~~	25SIGNATURES	25

Index

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (~~the~~ “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC ~~2002~~2003-DA Limited Partnership’s (~~the~~ “Partnership” or the “Registrant”) business, financial condition, and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership. All statements other than statements of historical facts included in and ~~prospects~~incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

~~All~~· ~~statements~~changes ~~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~~volumes ~~reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures~~ and ~~the~~worldwide 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.”demand;

~~Although~~· ~~forward-looking~~volatility ~~statements~~of ~~contained~~commodity inprices ~~this~~for 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,~~crude 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:oil;

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

changes in estimates of proved reserves;

· ~~declines~~inaccuracy ~~in the values~~ of ~~the~~reserve ~~Partnership’s~~estimates ~~natural gas~~ and ~~oil~~expected ~~properties~~production ~~resulting from impairments~~rates;

· ~~the~~declines ~~timing~~in ~~and~~the ~~extent~~value of the Partnership’s ~~success~~natural ingas ~~further developing~~ and ~~producing~~crude ~~the~~oil ~~Partnership’s~~properties ~~natural~~resulting ~~gas~~in ~~and oil reserves~~impairments;

· 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 activities;

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

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

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

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

· the effect of existing and future laws, governmental regulations and the political and economic climate of the ~~United~~U.S. ~~States~~as ofwell ~~America,~~as orother ~~U.S.~~oil producing countries throughout the world;

· changes in environmental laws, ~~and~~ the ~~regulations~~regulation and enforcement ~~related~~of those laws and the costs to comply with those laws;

· the ~~identification~~impact of ~~and~~environmental ~~severity~~events, ofgovernmental ~~environmental~~responses to the events and ~~governmental~~the ~~responses~~Managing General Partner's ability to ~~the~~insure adequately against such events;

· ~~the~~competition ~~effect~~in ofthe ~~natural~~oil ~~gas~~ and ~~oil~~gas ~~derivatives activities~~industry;

· the ~~availability~~success of ~~funding for~~ the ~~consideration~~Managing ~~payable~~General byPartner ~~PDC~~in ~~and~~marketing ~~its wholly-owned subsidiary to consummate~~ the ~~prospective~~Partnership’s ~~mergers~~oil ~~under the Acquisition Plan,~~ and ~~the timing of consummating any such mergers if at all~~gas;

· ~~conditions~~the ineffect ~~the~~of ~~capital~~natural ~~markets;~~gas and crude oil derivative activities;

· ~~losses~~the ~~possible~~availability ~~from~~of ~~pending~~funding orfor ~~future~~the ~~litigation.~~consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;

~~Further,~~· ~~the~~losses ~~Partnership~~possible ~~urges~~from ~~the~~pending 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,~~future onlitigation; ~~December 22, 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.

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

- 1 -

Index

~~PART~~PDC I2002-D –LIMITED ~~FINANCIAL INFORMATION~~PARTNERSHIP

~~Item~~(A 1.West ~~Financial~~Virginia ~~Statements~~Limited ~~(unaudited~~Partnership)

~~PDC~~Further, ~~2002~~the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership’s annual report on Form 10-DK ~~Limited~~for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on March 30, 2011 (“2010 Form 10-K”) and the Partnership’s other filings with the SEC for further information on risks and uncertainties that could affect the Partnership’s business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

Condensed Balance Sheets

(unaudited)

	September 30,			December 31,
	2010			2009*
Assets
Current assets:
Cash and cash equivalents	$	133,188		$	125,978
Accounts receivable		96,716			115,003
Oil inventory		32,303			34,652
Due from Managing General Partner-derivatives		389,512			234,618
Due from Managing General Partner-other, net		-			54,375
Total current assets		651,719			564,626
Natural gas and oil properties, successful efforts method, at cost		18,418,476			18,367,315
Less: Accumulated depreciation, depletion and amortization		(11,388,015	)		(10,553,171	)
Oil and gas properties, net		7,030,461			7,814,144
Due from Managing General Partner-derivatives		649,460			206,889
Other assets		81,794			67,711
Total noncurrent assets		7,761,715			8,088,744
Total Assets	$	8,413,434		$	8,653,370
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	34,062		$	13,878
Due to Managing General Partner-derivatives		229,933			200,841
Due to Managing General Partner-other, net		335,362			-
Total current liabilities		599,357			214,719
Due to Managing General Partner-derivatives		478,284			612,390
Asset retirement obligations		444,949			425,495
Total liabilities		1,522,590			1,252,604
Commitments and contingent liabilities
Partners' equity:
Managing General Partner		1,570,263			1,597,595
Limited Partners - 1,455.26 units issued and outstanding		5,320,581			5,803,171
Total Partners' equity		6,890,844			7,400,766
Total Liabilities and Partners' Equity	$	8,413,434		$	8,653,370

__________________________________

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

- 2 -

Index

~~PDC~~PART ~~2002-D~~I ~~Limited~~– ~~Partnership~~FINANCIAL INFORMATION

~~Condensed~~Item 1. Financial Statements ~~of Operations~~(unaudited)

(unaudited)

PDC 2002-D Limited Partnership
Condensed Balance Sheets
(unaudited)
	March 31,			December 31,
	2011				2010*
Assets

Current assets:
Cash and cash equivalents	$	133,287		$	133,238
Accounts receivable		134,693			133,783
Crude oil inventory		30,877			40,211
Due from Managing General Partner-derivatives		363,549			345,618
Total current assets		662,406			652,850


Natural gas and crude oil properties, successful efforts method, at cost		16,309,637			16,301,661
Less: Accumulated depreciation, depletion and amortization		(10,447,071	)		(10,238,283	)
Natural gas and crude oil properties, net		5,862,566			6,063,378

Due from Managing General Partner-derivatives		476,649			556,021
Other assets		91,127			86,464
Total noncurrent assets		6,430,342			6,705,863

Total Assets	$	7,092,748		$	7,358,713

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	18,929		$	40,662
Due to Managing General Partner-derivatives		355,823			297,142
Due to Managing General Partner-other, net		600,678			587,730
Total current liabilities		975,430			925,534

Due to Managing General Partner-derivatives		374,349			420,505
Asset retirement obligations		458,412			451,630
Total liabilities		1,808,191			1,797,669

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		1,253,076			1,306,336
Limited Partners - 1,455.26 units issued and outstanding		4,031,481			4,254,708
Total Partners' equity		5,284,557			5,561,044

Total Liabilities and Partners' Equity	$	7,092,748		$	7,358,713

	Three months ended September 30,					Nine months ended September 30,
	2010		2009			2010		2009
Revenues:
Natural gas and oil sales	$	316,072	$	313,399		$	1,043,508	$	899,687
Commodity price risk management gain (loss), net		331,564		(233,746	)		949,453		(591,669	)
Total revenues		647,636		79,653			1,992,961		308,018
Operating costs and expenses:
Natural gas and oil production costs		150,920		168,448			885,592		517,308
Direct costs - general and administrative		104,622		587			111,537		15,146
Depreciation, depletion and amortization		277,745		263,284			834,844		825,321
Accretion of asset retirement obligations		6,581		3,990			19,454		11,970
Total operating costs and expenses		539,868		436,309			1,851,427		1,369,745
Income (loss) from operations		107,768		(356,656	)		141,534		(1,061,727	)
Interest expense		-		(6,989	)		-		(6,989	)
Interest income		48		9,649			141		26,527
Net income (loss)	$	107,816	$	(353,996	)	$	141,675	$	(1,042,189	)
Net income (loss) allocated to partners	$	107,816	$	(353,996	)	$	141,675	$	(1,042,189	)
Less: Managing General Partner interest in net income (loss)		21,563		(70,799	)		28,335		(208,438	)
Net income (loss) allocated to Investor Partners	$	86,253	$	(283,197	)	$	113,340	$	(833,751	)
Net income (loss) per Investor Partner unit	$	59	$	(195	)	$	78	$	(573	)
Investor Partner units outstanding		1,455.26		1,455.26			1,455.26		1,455.26

_________________________________

~~See~~*Derived ~~accompanying~~from ~~notes~~audited to2010 ~~unaudited~~balance ~~condensed financial statements.~~sheet

See accompanying notes to unaudited condensed financial statements

- 3 -

Index

PDC 2002-D Limited Partnership

PDC 2002-D Limited Partnership
Condensed Statements of Operations
(unaudited)
	Three months ended March 31,
	2011			2010
Revenues:
Natural gas, NGLs and crude oil sales	$	363,839		$	404,334
Commodity price risk management (loss) gain, net		(55,406	)		462,025
Total revenues		308,433			866,359

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs		152,888			411,446
Direct costs - general and administrative		195,957			1,998
Depreciation, depletion and amortization		208,788			281,546
Accretion of asset retirement obligations		6,782			6,390
Total operating costs and expenses		564,415			701,380

(Loss) income from operations		(255,982	)		164,979

Interest income		49			47

Net (loss) income	$	(255,933	)	$	165,026

Net (loss) income allocated to partners	$	(255,933	)	$	165,026
Less: Managing General Partner interest in net (loss) income		(51,187	)		33,005
Net (loss) income allocated to Investor Partners	$	(204,746	)	$	132,021

Net (loss) income per Investor Partner unit	$	(141	)	$	91

Investor Partner units outstanding		1,455.26			1,455.26

Condensed Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	141,675		$	(1,042,189	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		834,844			825,321
Accretion of asset retirement obligations		19,454			11,970
Unrealized (gain) loss on derivative transactions		(702,479	)		1,381,754
Changes in operating assets and liabilities:
Decrease in accounts receivable		18,287			14,952
Decrease in oil inventory		2,349			28,604
Increase in other assets		(14,083	)		(13,736	)
Increase (decrease) in accounts payable and accrued expenses		20,184			(14,939	)
Decrease in Due from Managing General Partner - other, net		54,375			884,782
Increase in Due to Managing General Partner - other, net		335,362			-
Net cash provided by operating activities		709,968			2,076,519
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(51,161	)		(43,764	)
Net cash used in investing activities		(51,161	)		(43,764	)
Cash flows from financing activities:
Distributions to Partners		(651,597	)		(2,031,873	)
Net cash used in financing activities		(651,597	)		(2,031,873	)
Net increase in cash and cash equivalents		7,210			882
Cash and cash equivalents, beginning of period		125,978			125,048
Cash and cash equivalents, end of period	$	133,188		$	125,930
Cash payments for:
Interest	$	-		$	6,989

See accompanying notes to unaudited condensed financial statements.

- 4 -

Index

PDC 2002-D Limited Partnership
Condensed Statements of Cash Flows
(unaudited)
	Three months ended March 31,
	2011			2010
Cash flows from operating activities:
Net (loss) income	$	(255,933	)	$	165,026
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		208,788			281,546
Accretion of asset retirement obligations		6,782			6,390
Unrealized loss (gain) on derivative transactions		73,966			(277,806	)
Changes in operating assets and liabilities:
Increase in accounts receivable		(910	)		(14,240	)
Decrease in crude oil inventory		9,334			3,457
Increase in other assets		(4,663	)		(4,663	)
(Decrease) increase in accounts payable and accrued expenses		(21,733	)		106,102
Decrease in Due from Managing General Partner - other, net		-			54,375
Increase in Due to Managing General Partner - other, net		12,948			151,393
Net cash provided by operating activities		28,579			471,580

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties		(7,976	)		(5,273	)
Net cash used in investing activities		(7,976	)		(5,273	)

Cash flows from financing activities:
Distributions to Partners		(20,554	)		(466,261	)
Net cash used in financing activities		(20,554	)		(466,261	)

Net increase in cash and cash equivalents		49			46
Cash and cash equivalents, beginning of period		133,238			125,978
Cash and cash equivalents, end of period	$	133,287		$	126,024

See accompanying notes to unaudited condensed financial statements.

- 5 -

Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

Note 1−General and Basis of Presentation

~~The~~ PDC 2002-D Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership ~~on June 3~~, ~~2002~~ in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of ~~oil~~natural gas and ~~natural~~crude ~~gas~~oil properties. ~~Upon~~Business ~~completion~~operations of the Partnership commenced upon closing of an offering for the sale of Partnership units. Upon onfunding, ~~December~~the ~~31,~~Partnership ~~2002~~entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the ~~Partnership~~name ~~was~~PDC ~~funded~~Energy, to conduct and ~~commenced~~manage ~~its~~the ~~business~~Partnership’s ~~operations~~business. ~~The~~In accordance with the terms of the Limited Partnership ~~owns~~Agreement ~~natural~~(the ~~gas~~“Agreement”), ~~and~~the ~~oil~~Managing ~~wells~~General ~~located~~Partner inis ~~Colorado~~authorized ~~and~~to ~~from~~manage ~~the~~all ~~wells,~~activities of the Partnership ~~produces~~and initiates and ~~sells~~completes ~~natural~~substantially ~~gas~~all ~~and~~Partnership ~~oil~~transactions.

~~Purchasers~~As of ~~partnership~~March ~~units~~31, ~~subscribed~~2011, tothere ~~and~~were ~~fully~~1,034 ~~paid~~Investor ~~for 33~~Partners.15 PDC ~~units~~is ofthe ~~limited~~designated ~~partner~~Managing ~~interests~~General ~~and~~Partner ~~1,422.11 units~~ of ~~additional~~the ~~general~~Partnership ~~partner~~and ~~interests~~owns ata $20~~,000~~% ~~per~~Managing ~~unit~~General Partner ownership in the Partnership. InAccording ~~accordance~~to ~~with~~ the terms of the Limited Partnership Agreement, ~~(the “Agreement”)~~revenues, ~~Petroleum~~costs ~~Development~~and ~~Corporation,~~cash adistributions ~~Nevada~~of ~~Corporation~~the ~~that~~Partnership ~~now~~are ~~conducts~~allocated ~~business~~80% ~~under~~to the ~~name~~limited partners (“~~PDC~~Investor ~~Energy,~~Partners”), iswhich ~~the~~are ~~Managing~~shared ~~General~~pro ~~Partner~~rata, based upon the number of units in the Partnership ~~(hereafter~~, and 20% to the “Managing General Partner”. The orManaging ~~“PDC”)~~General ~~and~~Partner ~~has~~may arepurchase ~~20%~~Investor ~~Managing~~Partner ~~General~~units ~~Partner~~under ~~ownership~~certain incircumstances provided by the ~~Partnership~~Agreement, upon request of an individual Investor Partner. ~~Upon~~Through ~~completion~~March of31, 2011, the ~~drilling~~Managing ~~phase~~General ofPartner ~~the~~has repurchased 142.4 units of Partnership's ~~wells,~~interests ~~all~~from ~~additional~~Investor ~~general~~Partners ~~partners’~~at ~~units~~an ~~were~~average ~~converted~~price ~~into~~of ~~units~~$5,385 per unit. As of ~~limited~~March ~~partner~~31, ~~interests~~2011, ~~and~~the ~~thereafter~~Managing ~~became~~General ~~limited~~Partner ~~partners~~owns 27.8% of the Partnership.

~~Throughout~~In ~~the~~April ~~term of the Partnership~~2009, ~~revenues,~~a ~~costs,~~condition ~~and~~of ~~cash~~obligation ~~distributions~~arose ~~are~~subject ~~allocated 80%~~ to ~~the~~Section ~~limited~~4.02 ~~and additional general partners (collectively~~Distributions, ~~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~~Agreement. ~~Beginning~~Pursuant into ~~April 2009 when~~ the ~~conditions of the obligation arose and expiring upon the termination of~~ Performance Standard Obligation provision, which expires in June 2013, the Partnership modified the ~~allocation~~distribution rate of ~~all items of profit and loss and resulting~~ cash ~~available~~distributions ~~for distribution~~ from that described ~~above~~in the previous paragraph, between the Managing General Partner and the Investor Partners~~, pursuant to Section 4~~.~~02 Distributions, of the Partnership Agreement.~~ ~~For~~During the ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011 and ~~2009~~March 31, 2010, distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $742,~~653~~038 and $8742,~~614~~494, respectively, as a result of the Preferred Cash Distribution made under the terms ofin ~~this~~Section ~~provision~~4.02. For more information concerning the Performance Standard Obligation, see Note 68, Partners’ Equity and Cash Distributions to the Partnership financial statements that accompany the ~~2009~~2010 Form 10-K.

AsThe ofPartnership ~~September~~expects ~~30,~~continuing ~~2010,~~operations ~~there~~of ~~were~~its ~~1,041~~natural ~~Investor~~gas ~~Partners. As~~and ofcrude ~~September~~oil ~~30,~~properties ~~2010,~~until ~~the~~such ~~Managing~~time ~~General~~the ~~Partner~~Partnership’s ~~has~~wells ~~repurchased~~are ~~137.13~~depleted ~~units~~or ofbecome ~~the~~uneconomical ~~total~~to 1produce,~~455.26~~ ~~outstanding~~at ~~units~~which oftime ~~Partnership~~they ~~interests~~may ~~from~~be ~~Investor~~sold ~~Partners~~or atplugged, anreclaimed ~~average~~and ~~price~~abandoned. The Partnership’s maximum term of ~~$5,533~~existence ~~per~~extends ~~unit~~through ~~and~~December 31, as2050, aunless ~~result,~~dissolved ~~participates~~by incertain conditions stipulated within the ~~sharing~~Agreement ofwhich ~~revenues,~~are ~~costs~~unlikely ~~and~~to ~~cash~~occur ~~distributions~~at asthis ~~both~~time, anor ~~investor~~by ~~partner~~written ~~and~~consent asof the ~~Managing~~Investor ~~General~~Partners ~~Partner~~owning a majority of outstanding units at that time.

~~The~~In the Managing General Partner’s opinion, ~~under~~ the ~~terms~~accompanying ofinterim ~~the~~unaudited ~~Drilling~~condensed ~~and~~financial ~~Operating~~statements ~~Agreement~~contain all adjustments (~~the~~consisting ~~“D&O~~of ~~Agreement”~~only normal recurring adjustments), ~~has~~necessary ~~full~~for ~~authority~~a tofair ~~conduct~~statement of the Partnership’s ~~business~~financial ~~and~~statements ~~actively~~for ~~manage~~interim periods in accordance with accounting principles generally accepted in the ~~Partnership~~United States of America ("U. ~~The~~S. ~~Partnership~~GAAP") ~~expects~~and ~~continuing~~with ~~operations~~the instructions to Form 10-Q and Article 10 of ~~its~~Regulation ~~natural~~S-X ~~gas~~of the Securities and ~~oil~~Exchange ~~properties~~Commission ~~until~~(“SEC”). Accordingly, pursuant to such ~~time~~rules ~~that~~and regulations, certain notes and other financial information included in the ~~Partnership’s~~audited ~~wells~~financial ~~are~~statements ~~depleted~~have been condensed or ~~become~~omitted. The ~~uneconomical~~information topresented ~~produce,~~in atthis ~~which~~quarterly ~~time~~report ~~that~~on ~~well~~Form ~~may~~10-Q should be ~~sold~~read orin ~~plugged,~~conjunction ~~reclaimed~~with the Partnership’s audited financial statements and ~~abandoned~~notes thereto included in the Partnership’s 2010 Form 10-K. The Partnership’s ~~maximum~~accounting ~~term~~policies ofare ~~existence~~described ~~extends~~in ~~through~~the ~~December~~Notes 31to Financial Statements in the Partnership’s 2010 Form 10-K and updated, ~~2050~~as necessary, ~~unless~~in ~~dissolved~~this byForm ~~certain~~10-Q. The ~~conditions~~results ~~stipulated~~of ~~within~~operations for the ~~Agreement~~three ~~(which~~months ~~are~~ended ~~unlikely~~March to31, ~~occur~~2011, atand ~~this~~the ~~time)~~cash orflows byfor ~~written~~the ~~consent~~same period, are not necessarily indicative of the ~~Investor~~results ~~Partners~~to ~~owning~~be aexpected ~~majority~~for ofthe ~~outstanding~~full ~~units~~year ator ~~that~~any ~~time~~other future period.

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~~6 ~~Article 10 of Regulation S~~-X of the Securities and Exchange Commission, or SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2009 Form 10-K. The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2009 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three and nine months ended September 30, 2010, and the cash flows for the nine months ended September 30, 2010, are not necessarily indicative of the results to be expected for the full year or any other future period.

- 5 -

Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the ~~Financial Accounting Standards Board (“~~FASB”) issued changes ~~clarifying existing disclosure requirements~~ related to fair value measurements~~. The~~ ~~update~~requiring ~~also~~gross ~~added~~presentation aof ~~new~~activities ~~requirement~~within tothe ~~disclose~~Level ~~fair~~3 ~~value~~roll ~~transfers~~forward, inwhereby ~~and~~entities ~~out~~must ofpresent ~~Levels~~separately 1information ~~and~~about 2purchases, sales, issuances and ~~describe~~settlements. These ~~the~~changes ~~reasons~~were effective for the ~~transfers. The~~Partnership’s ~~adoption~~financial ofstatements ~~these~~issued ~~changes~~for asannual ofreporting ~~January~~periods, 1and for interim reporting periods within the year, ~~2010~~beginning after December 15, 2010. The adoption of this change 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 condensed balance ~~sheet~~sheets under the captions “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or “Due to Managing General Partner–derivatives,” in the case of net unrealized losses.

-The 6following table presents transactions with the Managing General Partner reflected in the condensed balance sheet line item – “Due from (to) Managing General Partner-other, net,” which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.

Index

	March 31,			December 31,
	2011			2010

Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	99,589		$	83,892
Commodity price risk management, realized gain		10,216			48,073
Other (1)		(710,483	)		(719,695	)
Total Due to Managing General Partner-other, net	$	(600,678	)	$	(587,730	)

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 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.

	September 30,			December 31,
	2010			2009
Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	125,878		$	175,272
Commodity Price Risk Management, Realized Gains		33,465			155,373
Other (1)		(494,705	)		(276,270	)
Total Due (to) from Managing General Partner-other, net	$	(335,362	)	$	54,375

(1)

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

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

	Three months ended September 30,					Nine months ended September 30,
	2010			2009		2010		2009
Well operations and maintenance	$	124,871		$	140,996	$	800,411	$	434,713
Gathering, compression and processing fees		11,441			11,079		34,942		31,786
Direct costs - general and administrative		104,622			587		111,537		15,146
Cash distributions (1) (2)		(5,134	)		236,203		111,535		474,138

(1) Cash distributions to the Managing General Partner for the three and nine months ended September 30, 2010, were reduced by $9,357 and $74,653, respectively, and for the three and nine months ended September 30, 2009 were reduced by $30,284 and $87,614, respectively, due to Preferred Cash Distribution made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

(2) Cash distributions include $1,796 and $55,868 during the three and nine months ended September 30, 2010, respectively, and $74,555 and $155,379 during the three and nine months ended September 30, 2009, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

Note 4−Fair Value Measurements

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

- 7 -

Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

The following table presents Partnership transactions, byexcluding ~~hierarchy~~derivative ~~level~~transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the ~~Partnership’s~~Managing ~~derivative~~General ~~financial~~Partner ~~instruments~~and its affiliates for the three months ended March 31, ~~including~~2011 ~~both~~and ~~current~~2010. “Well operations and ~~non-current~~maintenance” ~~portions~~and ~~measured~~“Gathering, atcompression ~~fair~~and ~~value~~processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.

	Quoted Prices in Active Markets			Significant Unobservable Inputs
	Three months ended March 31,
	(Level 1)			(Level 3)			Total
	2011			2010
As of December 31, 2009
Well operations and maintenance	$	124,960		$	379,373
Assets:
Gathering, compression and processing fees		10,745			12,086
Commodity based derivatives	$	210,848		$	230,659		$	441,507
Direct costs - general and administrative		195,957			1,998
Total assets		210,848			230,659			441,507
Cash distributions (1) (2)		3,861			89,696
Liabilities:
Commodity based derivatives		(13,979	)		(58,314	)		(72,293	)
Basis protection derivative contracts		-			(740,938	)		(740,938	)
Total liabilities		(13,979	)		(799,252	)		(813,231	)
Net asset (liability)	$	196,869		$	(568,593	)	$	(371,724	)
As of September 30, 2010
Assets:
Commodity based derivatives	$	957,112		$	81,860		$	1,038,972
Total assets		957,112			81,860			1,038,972
Liabilities:
Commodity based derivatives		-			(51,525	)		(51,525	)
Basis protection derivative contracts		-			(656,692	)		(656,692	)
Total liabilities		-			(708,217	)		(708,217	)
Net asset (liability)	$	957,112		$	(626,357	)	$	330,755

~~The~~(1) ~~following~~Cash ~~table~~distributions ~~presents~~include ~~the~~$1,788 ~~changes~~and of$38,937 during the ~~Partnership’s~~three ~~Level~~months 3ended ~~derivative~~March ~~financial~~31, ~~instruments~~2011 ~~measured~~and 2010, respectively, related to equity cash distributions on aInvestor ~~recurring~~Partner ~~basis:~~units repurchased by PDC.

	Nine months ended
	September 30, 2010
Fair value, net liability, as of December 31, 2009	$	(568,593	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		66,676
Settlements		(124,440	)
Fair value, net liability, as of September 30, 2010	$	(626,357	)
Change in unrealized gain (loss) relating to assets (liabilities) still held as of September 30, 2010 included in statement of operations line item:
Commodity price risk management, net	$	175,888

(2)

Cash distributions to the Managing General Partner for the three months ended March 31, 2011 and 2010, were reduced by $2,038 and $42,494, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

~~See~~ Note 5,4−Fair ~~Derivative~~Value of Financial Instruments~~, for additional disclosure related to the Partnership’s derivative financial instruments.~~

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

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

Assets:
Commodity based derivatives	$	831,194	$	9,004		$	840,198		$	867,993	$	33,646		$	901,639
Total assets		831,194		9,004			840,198			867,993		33,646			901,639

Liabilities:
Commodity based derivatives		-		(104,641	)		(104,641	)		-		(84,806	)		(84,806	)
Basis protection derivative contracts		-		(625,531	)		(625,531	)		-		(632,841	)		(632,841	)
Total liabilities		-		(730,172	)		(730,172	)		-		(717,647	)		(717,647	)

Net asset (liability)	$	831,194	$	(721,168	)	$	110,026		$	867,993	$	(684,001	)	$	183,992

- 8 -

Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

~~Non-Derivative~~The ~~Assets~~following ~~and~~table ~~Liabilities. The~~presents ~~carrying~~a ~~values~~reconciliation of the ~~financial~~Partnership’s ~~instruments~~Level ~~comprising~~3 ~~current assets and current liabilities approximate~~ fair value ~~due to the short-term maturities of these instruments~~measurements.

	Three months ended
	March 31, 2011			March 31, 2010
Fair value, net liability, beginning of year	$	(684,001	)	$	(568,593	)
Changes in fair value included in statement of operations line item -
Commodity price risk management, net		(65,870	)		(60,082	)
Settlements		28,703			(184,219	)
Fair value, net liability, end of period	$	(721,168	)	$	(812,894	)

Change in unrealized loss relating to assets (liabilities) still held as of March 31, 2011 and 2010, respectively, included in statement of operations line item: Commodity price risk management, net	$	(65,061	)	$	(73,872	)

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

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

Note 5−Derivative Financial Instruments

As of ~~September~~March 3031, ~~2010~~2011, the Partnership had derivative instruments, ~~comprised of commodity collars, commodity fixed-price swaps and a basis protection swap,~~ in place for a portion of its anticipated production through 2013 for a total of ~~535~~443,~~597~~869 MMbtu of natural gas and 52,~~642~~914 Bbls of ~~oil. Partnership~~crude ~~policy prohibits the use of natural gas and~~ oil ~~derivative instruments for speculative purposes~~.

The following table ~~summarizes~~presents the ~~line~~location ~~item~~ and fair value amounts of the Partnership’s derivative instruments inon the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.

					Fair Value	~~Fair Value~~
Derivative instruments not designated as hedge (1):				Balance Sheet Line Item		September 30, 2010			December 31, 2009
			Balance Sheet		March 31,			December 31,
Derivative Assets:		Current
Derivative instruments not designated as hedge (1):			Line Item		2011			2010
		Commodity contracts		Due from Managing General Partner-derivatives		$	389,512		$	234,618
Derivative Assets:	Current
		Non Current
	Commodity contracts		Due from Managing General Partner-derivatives		$	363,549		$	345,618
		Commodity contracts		Due from Managing General Partner-derivatives			649,460			206,889
	Non Current
Total Derivative Assets						$	1,038,972		$	441,507
	Commodity contracts		Due from Managing General Partner-derivatives			476,649			556,021
Derivative Liabilities:		Current
Total Derivative Assets					$	840,198		$	901,639
		Commodity contracts		Due to Managing General Partner-derivatives		$	37,085		$	14,362
Derivative Liabilities:	Current
		Basis protection contracts		Due to Managing General Partner-derivatives			192,848			186,479
	Commodity contracts		Due to Managing General Partner-derivatives		$	104,641		$	84,806
		Non Current
	Basis protection contracts		Due to Managing General Partner-derivatives			251,182			212,336
		Commodity contracts		Due to Managing General Partner-derivatives			14,440			57,931
	Non Current
	Basis protection contracts	~~Basis protection contracts~~	Due to Managing General Partner-derivatives	~~Due to Managing General Partner-derivatives~~		374,349	~~463,844~~		420,505	~~554,459~~
Total Derivative Liabilities					$	$730,172	~~708,217~~	$	$717,647	~~813,231~~

(1) As of ~~September~~March 3031, ~~2010~~2011 and December 31, ~~2009~~2010, none of the Partnership’s derivative instruments were designated as hedges.

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

	Three months ended September 30,
	2010							2009
Statement of operations line item	Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized			Realized and Unrealized Gain For the Current Period		Total		Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized			Realized and Unrealized Loss For the Current Period			Total
Commodity price risk management, net
Realized gain (loss)	$	15,998		$	20,962	$	36,960	$	201,615		$	(827	)	$	200,788
Unrealized (loss) gain		(15,998	)		310,602		294,604		(201,615	)		(232,919	)		(434,534	)
Total commodity price risk management gain (loss), net	$	-		$	331,564	$	331,564	$	-		$	(233,746	)	$	(233,746	)

	Nine months ended September 30,
	2010							2009
Statement of operations line item	Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized			Realized and Unrealized Gain For the Current Period		Total		Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized			Realized and Unrealized Gain (Loss) For the Current Period			Total
Commodity price risk management, net
Realized gain	$	58,800		$	188,174	$	246,974	$	636,972		$	153,113		$	790,085
Unrealized (loss) gain		(58,800	)		761,279		702,479		(636,972	)		(744,782	)		(1,381,754	)
Total commodity price risk management gain (loss), net	$	-		$	949,453	$	949,453	$	-		$	(591,669	)	$	(591,669	)

- 9 -

Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2010~~2011

(unaudited)

~~Concentration~~The offollowing ~~Credit~~table ~~Risk.~~presents Athe ~~significant~~impact ~~component~~ of the Partnership’s ~~future liquidity is concentrated in~~ derivative instruments ~~that~~on ~~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~~accompanying ~~facility~~condensed ~~agreement,~~statements asof ~~counterparties to the derivative contracts~~operations. ~~To date, the Partnership has experienced no counterparty defaults.~~

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

Commodity price risk management, net
Realized gain	$	14,697		$	3,863		$	18,560		$	170,429		$	13,790	$	184,219
Unrealized (loss) gain		(14,697	)		(59,269	)		(73,966	)		(170,429	)		448,235		277,806
Total commodity price risk management (loss) gain, net	$	-		$	(55,406	)	$	(55,406	)	$	-		$	462,025	$	462,025

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

Note 6−Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the natural gas and crude oil ~~business~~industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. During the ~~first~~three ~~nine~~ months ofended ~~2010~~March 31, 2011, there were no new environmental remediation projects identified by the Managing General Partner ~~identified~~related ~~existing~~to ~~ground~~the ~~contamination~~Partnership. As atof ~~three~~March of31, 2011, the Partnership’s ~~well~~has ~~pads~~an ~~involving~~accrual ~~seven~~for ~~wells~~one ~~and~~well in the ~~Partnership~~amount ~~incurred expenses~~ of $~~0.4~~7,000 ~~million~~which ~~for~~is ~~ground~~included ~~contamination~~in ~~remediation~~line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheet. AtAs ~~September~~of 30December 31, 2010, anthe Partnership accrued ~~balance~~for three of ~~approximately~~the ~~$5,200~~Partnership’s ~~for~~well pads involving three wells in the ~~estimated~~amount ~~environmental~~of ~~remediation~~$31,000 ~~liability~~which is included in ~~the Balance Sheet~~ line item captioned “Accounts payable and accrued expenses.” on the condensed Balance Sheet. The Managing General Partner is not aware of any environmental claims existing as of ~~September~~March 3031, ~~2010~~2011, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.

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 nine wells in this region. The Notice alleged a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered into negotiations with the CDPHE regarding this notice and a settlement was accepted by CDPHE in November 2010. This settlement did not have a material impact on the Partnership’s financial position or results of operations.

- 10 -

Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

Partnership Overview

PDC 2002-D Limited Partnership engages in the development, production and sale of ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~oil. The Partnership began ~~oil~~natural gas and ~~gas~~crude oil operations in December 2002 and operates 3635 gross (3231.34 net) productive wells located in the Rocky Mountain Region in the state of Colorado. OfIn ~~the~~addition, ~~Partnership’s~~one ~~total~~(0.9 net) well ~~count,~~in 35the ~~are~~Wattenberg ~~producing~~Field ~~and~~is ~~one~~temporarily ~~Wattenberg~~not ~~Field~~in ~~well~~production isat ~~not~~March ~~producing~~31, 2011 due to ~~mechanical~~equipment problems. The Managing General Partner markets the Partnership’s natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, or local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

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

In ~~June~~November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC ~~2004~~2005-A Limited Partnership, PDC ~~2004~~2005-B Limited Partnership, ~~PDC~~and ~~2004-C~~the ~~Limited~~2005 ~~Partnership~~Rockies ~~and~~Region ~~PDC~~Private ~~2004-D~~ Limited Partnership (collectively, the “~~2004~~2005 ~~partnerships~~Partnerships”). PDC serves as the ~~managing~~Managing ~~general~~General ~~partner~~Partner of each of the ~~2004~~2005 ~~partnerships~~Partnerships. ~~Definitive~~The ~~proxy~~special ~~statements~~meetings ~~for~~whereby ~~each of the 2004 partnerships requesting approval for the applicable merger were mailed to the~~ non-affiliated ~~Investor~~investor ~~Partners~~partners of the ~~2004~~2005 ~~partnerships~~Partnerships inwill ~~early~~have ~~October~~an ~~2010. Special~~opportunity ~~meetings~~to ~~were~~vote ~~held~~and ~~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~~respective merger~~. These~~ ~~mergers~~agreements ~~were~~are ~~completed~~currently onscheduled ~~December~~for 17June 15, ~~2010~~2011.

InThe ~~November~~feasibility ~~2010, PDC~~ and atiming ~~wholly-owned subsidiary~~ of ~~PDC~~any ~~entered~~future ~~into~~purchase ~~separate~~offer ~~merger~~by ~~agreements with each of~~ PDC ~~2005-A~~to ~~Limited~~any ~~Partnership,~~additional ~~PDC 2005-B Limited Partnership~~partnership, ~~and~~including ~~the~~this ~~2005 Rockies Region Private Limited~~ Partnership ~~(collectively~~, ~~the~~depends ~~“2005~~on ~~partnerships”). PDC~~that ~~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~~suitability ~~merger. Upon~~in ~~completion~~meeting ~~of the SEC review process,~~ a ~~definitive~~set ~~proxy statement will be mailed to the 2005 partnerships’ non-affiliated Investor Partners requesting their approval~~ of ~~the~~criteria ~~merger~~that ~~transactions. Pursuant to each merger agreement~~includes, ifbut ~~the merger~~ is ~~approved~~not bylimited ~~the~~to, ~~holders of a majority of~~ the ~~limited~~following: ~~partnership~~age ~~units~~and ~~held by the non~~productive-~~affiliated~~life ~~Investor~~stage ~~Partners~~characteristics of ~~each~~the ~~respective~~ partnership,’s as well ~~as,~~inventory; ~~the~~favorability ~~satisfaction~~ of ~~other~~economics ~~customary~~for ~~closing~~Wattenberg ~~conditions,~~Field ~~then~~well ~~such~~refracturing; ~~partnership will merge with~~ and ~~into~~SEC areporting ~~wholly-owned~~compliance ~~subsidiary~~status ofand ~~PDC. PDC~~timing ~~has~~associated ~~offered~~with togaining ~~pay~~all annecessary ~~aggregate~~regulatory ofapprovals ~~approximately~~required ~~$36.4 million~~ for ~~the~~a ~~limited~~merger ~~partnership~~and ~~units~~repurchase ~~of the 2005 partnerships in connection with the mergers~~offer. ~~Although~~There ~~there~~ is no assurance ofthat ~~the~~any ~~likelihood~~merger orand ~~timing~~acquisition ofwill ~~the~~occur, ~~completion~~as ofa ~~the~~result ~~SEC~~of ~~proxy~~PDC’s ~~disclosure~~proposed ~~review~~repurchase ~~process~~offers orto ~~whether~~ the ~~Partnership~~2005 ~~will~~Partnerships, ~~obtain~~or ~~the~~any ~~necessary~~potential ~~approvals~~proposed ~~from~~repurchase ~~non-affiliated~~offer ~~investors,~~to ~~each~~any ~~merger~~other of ~~the~~PDC’s ~~2005~~various ~~partnerships~~public islimited ~~expected~~partnerships, toincluding ~~close~~this ~~during~~Partnership, ~~the~~should ~~first~~they ~~half of 2011~~occur.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The feasibility and timing of any future purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership’s suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership’s well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated 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.

Additional Codell Formation Development Plan

The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells which may provide for additional reserve development ~~and~~of natural gas, NGLs and crude oil 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~~2012. 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, all within an existing well bore.

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

During the fourth quarter 2010, the Managing General Partner began ~~withholding~~a ~~funds~~program ~~from~~for ~~several~~its ofaffiliated ~~the PDC sponsored~~ partnerships, ~~on a pro-rata basis allocated~~ to ~~the~~begin ~~Managing~~accumulating ~~General~~cash ~~Partner and Investor Partners based on their proportional ownership interest,~~ from ~~distributable~~ cash flows ~~of the Partnership resulting~~ from ~~current~~operating ~~production. The~~activities ~~funds retained are necessary for the Partnership~~ to pay for ~~additional~~future ~~Codell~~refracturing ~~formation~~and ~~development~~recompletion costs. This ~~and~~program will materially reduce, up to 100%, ~~distributable~~ cash ~~flows~~available for distributions of the ~~Partnership~~partnerships 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 Managing General Partner.

Current estimated costs for these well refracturings or recompletions are between $175,000 and $240,000 per activity. As of March 31, 2011, this Partnership had scheduled to complete 32 additional Codell formation development opportunities. Total withholding for these activities from the Partnership’s cash available for distributions is estimated to be between $5.6 million and $7.7 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. As of April 30, 2011, no funds have been withheld from the Partnership distributions for this recompletion and refracturing.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Current~~If ~~estimated~~any ~~costs~~or ~~for~~all ~~these~~of ~~well~~the ~~refracturings~~Partnership’s ~~and~~Wattenberg ~~recompletions~~wells are ~~between~~not ~~$150,000~~refractured ~~and~~or ~~$200~~recompleted,~~000~~ ~~per~~the ~~activity. This~~ Partnership ~~potentially~~will ~~has~~experience 32a ~~additional~~reduction ~~Codell~~in ~~formation~~proved ~~development~~reserves ~~opportunities~~currently assigned to these wells. ~~Total~~Both ~~withholding~~the ~~for~~number ~~these~~and ~~activities~~timing ~~from~~of the ~~Partnership’s~~additional ~~distributable~~Codell ~~cash~~formation ~~flows~~development isactivities ~~estimated~~will to be ~~between~~based ~~$4.8~~on ~~million~~the ~~and~~availability ~~$6.4~~of ~~million~~cash withheld from Partnership distributions. The Managing General Partner ~~will~~believes ~~continually~~that, ~~evaluate~~based ~~the~~on ~~timing~~projected ofrefracturing ~~commencing~~and ~~these~~recompletion costs and projected cash withholding, all scheduled Partnership additional Codell formation development ~~activities~~activity ~~based~~will onbe ~~engineering~~completed ~~data~~within ~~and~~ a ~~favorable~~five ~~commodity~~year ~~price~~period. Any ~~environment~~funds innot ~~order~~used tofor ~~maximize~~refracturing, ~~the~~recompletion ~~financial~~or ~~benefit~~other ofoperational needs will be distributed to the ~~additional~~Managing ~~well~~General ~~development~~Partner and Investor Partners based on their proportional ownership interest.

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

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales ~~increased~~decreased 1610% or $~~0.1~~40,000 ~~million~~ for the first ~~nine~~three months of ~~2010~~2011 compared to the first ~~nine~~three months of ~~2009~~2010, ~~even~~while ~~though~~sales ~~production~~ volumes ~~decreased~~declined 205% period-to-period. ~~This increase was driven primarily by the improved commodity price environment and the increase in the Partnership’s oil production as a percentage of total production.~~ The average sales price per Mcfe, excluding the impact of realized derivative gains, was $56.7500 for the current year period compared to $36.9835 for the same period a year ago. ~~Comparatively,~~Realized ~~the~~derivative ~~total~~gains ~~per~~from ~~Mcfe~~natural ~~price~~gas ~~realized,~~and ~~consisting~~crude ofoil ~~the average~~ sales ~~price~~contributed ~~and~~an ~~realized~~additional ~~derivative~~$0.30 ~~gains,~~per ~~decreased~~Mcfe toor $~~7.11~~19,000 ~~for~~to the ~~current~~first ~~year~~three ~~nine~~ months ~~from~~of ~~$7.47~~2011 ~~for~~total ~~the~~revenues ~~same~~compared ~~prior~~to ~~year~~an ~~period~~additional $2. ~~The~~89 ~~decrease~~or ~~was~~$184,000 ~~primarily due~~ to ~~realized~~the ~~derivative~~first ~~gains~~three ~~from~~months ~~natural~~of ~~gas~~2010. Comparatively, ~~and~~the ~~oil~~total ~~sales~~realized ~~contributing~~price ~~only $1.36~~ per Mcfe, orconsisting ~~$0.2~~of ~~million to~~ the ~~first~~average ~~nine~~sales ~~months~~price ofand ~~2010~~realized ~~total~~derivative ~~revenues~~gains, asdecreased ~~compared~~ to $36.4930 ~~per~~for ~~Mcfe~~the orcurrent ~~$0.8~~year ~~million~~three tomonths ~~the~~from ~~nine~~$9.24 for ~~months~~the ofsame ~~2009~~prior ~~total~~year ~~revenues~~period.

~~The~~Current ~~Partnership’s~~period ~~combined natural gas and oil~~ production ~~expenses~~ and ~~direct~~operating costs~~−administrative~~ ~~and~~decreased ~~general, increased~~ by approximately $~~0.4~~259,000, ~~million~~primarily ~~during~~due ~~the~~to first quarter 2010 ~~nine~~environmental ~~month~~remediation ~~period~~projects. ~~Higher~~Direct ~~production~~costs-general ~~expenditures~~and ~~were~~administrative ~~primarily~~increased ~~due to environmental remediation activities~~ during the ~~current nine month period involving seven Partnership wells at~~ three ~~well~~months ~~pads. See~~ended ~~Note~~March 631, ~~Commitments and Contingencies~~2011, compared to the ~~accompanying~~same ~~unaudited~~period ~~condensed~~in ~~financial statements~~2010, ~~included~~by inapproximately ~~this~~$194,000 ~~report. Higher~~principally ~~administrative and general expenses were~~ due to ~~higher~~increased fees for ~~audit~~professional services. ~~These audit services were conducted under the 2010 Partnership SEC reporting compliance effort related to the filing of the Partnership’s financial statements for the years 2005 through 2009.~~

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

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

	Three months ended September 30,								Nine months ended September 30,
	Three months ended March 31,
	2010			2009		Change			2010		2009		Change
	2011			2010		Change
Number of producing wells (end of period)		35			3635		(1-	)		35		36		(1	)
Production (1)
Production(1)
Natural gas (Mcf)		4743,~~455~~379			5646,~~394~~127		-166	%		~~145,359~~		~~179,321~~		~~-19~~	%
Oil (Bbl)		1,980			2,530		-22	%		6,015		7,811		-23	%
NGLs (Bbl)		840			877		-4	%
Natural gas equivalents (Mcfe) (2)		59,335			71,574		-17	%		181,449		226,187		-20	%
Crude oil (Bbl)		2,040			2,053		-1	%
Natural Gas and Oil Sales
Natural gas equivalents (Mcfe)(2)		60,659			63,707		-5	%
Natural gas	$	177,219		$	160,090		11	%	$	612,797	$	536,623		14	%
Average Mcfe per day		674			708		-5	%
Oil		138,853			153,309		-9	%		430,711		363,064		19	%
Natural Gas, NGLs and Crude Oil Sales
Total natural gas and oil sales	$	316,072		$	313,399		1	%	$	1,043,508	$	899,687		16	%
Natural gas	$	142,087		$	217,081		-35	%
Realized Gain on Derivatives, net
NGLs		45,471			38,730		17	%
Natural gas	$	6,841		$	156,805		-96	%	$	165,334	$	594,077		-72	%
Crude oil		176,281			148,523		19	%
Oil		30,119			43,983		-32	%		81,640		196,008		-58	%
Total natural gas, NGLs and crude oil sales	$	363,839		$	404,334		-10	%
Total realized gain on derivatives, net	$	36,960		$	200,788		-82	%	$	246,974	$	790,085		-69	%
Realized Gain (Loss) on Derivatives, net
Average Selling Price (excluding realized gain on derivatives)
Natural gas	$	40,316		$	159,315		-75	%
Natural gas (per Mcf)	$	3.73		$	2.84		32	%	$	4.22	$	2.99		41	%
Crude oil		(21,756	)		24,904		-187	%
Oil (per Bbl)		70.13			60.60		16	%		71.61		46.48		54	%
Total realized gain on derivatives, net	$	18,560		$	184,219		-90	%
Natural gas equivalents (per Mcfe)		5.33			4.38		22	%		5.75		3.98		45	%
Average Selling Price (excluding realized gain (loss) on derivatives)
Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.28		$	4.71		-30	%
Natural gas (per Mcf)	$	3.88		$	5.62		-31	%	$	5.35	$	6.31		-15	%
NGLs (per Bbl)		54.13			44.16		23	%
Oil (per Bbl)		85.34			77.98		9	%		85.18		71.57		19	%
Crude oil (per Bbl)		86.41			72.34		19	%
Natural gas equivalents (per Mcfe)		56.9500			76.1835		-175	%		~~7.11~~		~~7.47~~		-5	%
Average Lifting Cost (per Mcfe) (3)	$	2.54		$	2.35		8	%	$	4.88	$	2.29		113	%
Average Selling Price (including realized gain (loss) on derivatives)
Operating costs and expenses
Natural gas (per Mcf)	$	4.20		$	8.16		-48	%
Direct costs - general and administrative	$	104,622		$	587		*		$	111,537	$	15,146		*
NGLs (per Bbl)		54.13			44.16		23	%
Depreciation, depletion and amortization	$	277,745		$	263,284		5	%	$	834,844	$	825,321		1	%
Crude oil (per Bbl)		75.75			84.47		-10	%
Cash distributions	$	12,135		$	959,660		-99	%	$	651,597	$	2,031,873		-68	%
Natural gas equivalents (per Mcfe)		6.30			9.24		-32	%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	2.52		$	6.46		-61	%
Depreciation, depletion and amortization		3.44			4.42		-22	%
Operating costs and expenses:
Direct costs - general and administrative	$	195,957		$	1,998		*
Depreciation, depletion and amortization		208,788			281,546		-26	%
Cash distributions	$	20,554		$	466,261		-96	%

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

_______________

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

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

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

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

(1)

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

(2)

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

(3)

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

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

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

MBbl – One thousand barrels

Mcf – One thousand cubic feet

MMcf – One million cubic feet

Mcfe – One thousand cubic feet of natural gas equivalents

MMcfe – One million cubic feet of natural gas equivalents

MMbtu – One million British Thermal Units

Natural Gas, NGLs and Crude Oil Sales

~~Nine~~For the three months ended ~~September~~March 3031, ~~2010~~2011 as compared to ~~nine~~the ~~months~~same ~~ended~~period ~~September~~in 302010, ~~2009~~natural gas, NGLs and crude oil production decreased 5% on an energy equivalency-basis.

~~The~~Three ~~$0.1~~months ~~million,~~ended orMarch ~~16%~~31, ~~increase~~2011 ~~in sales for the 2010 nine month period~~ as compared to ~~the~~three ~~prior~~months ~~year~~ended ~~period,~~March ~~was primarily a reflection of the significantly higher average sales price per Mcfe of 45%~~31, which was partially offset by a production volume decrease of 20%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.75 for the current year nine month period compared to $3.98 for the same period a year ago.2010

~~Natural~~The ~~gas~~$40,000, ~~and~~or ~~oil~~10%, ~~revenues~~decrease ~~increased~~in bysales ~~14%~~for ~~and~~the ~~19%,~~2011 ~~respectively.~~three ~~The~~month ~~Partnership’s~~period ~~natural~~as ~~gas~~compared ~~revenue~~to ~~increase~~the ~~resulted~~prior ~~from~~year ~~rising~~period ~~commodity~~was ~~prices~~primarily ~~per~~a ~~Mcf,~~reflection of ~~41%,~~a ~~which~~sales ~~were~~volume ~~partially~~decrease ~~offset~~of by5% ~~lower~~and ~~Partnership~~a ~~natural~~decrease ~~gas~~in ~~production~~sales ~~volumes~~prices of 195%. ~~This~~The ~~compares~~average tosales ~~the~~price ~~slightly~~per ~~higher~~Mcfe, ~~oil~~excluding ~~revenue increase in which~~ the ~~rise~~impact inof ~~commodity~~realized ~~prices~~derivative ~~per Bbl~~gains, ~~of 54%~~ was ~~partially~~$6.00 ~~offset~~for by the ~~decline~~current inyear ~~oil~~three ~~production~~month ~~volumes~~period ofcompared ~~23%~~to ~~during~~$6.35 for the ~~current~~same ~~nine~~period ~~month~~a ~~period~~year ago.

~~Three~~Natural ~~months~~gas ~~ended~~revenues ~~September~~decreased by 35% and were partially offset by increases in NGLs and crude oil revenues of 17% and 19%, respectively. The Partnership’s natural gas revenue decrease resulted from decreased commodity prices per Mcf, of 30%, ~~2010~~and asdecreases ~~compared~~in natural gas production volumes of 6%. The increase in NGLs revenue was due to ~~three~~increased ~~months~~commodity ~~ended~~prices ~~September~~per 30Bbl, ~~2009~~of 23%, partially offset by a decrease of 4% in NGLs production volumes. The crude oil revenue increase is due primarily to the rise in commodity prices per Bbl, of 19%, partially offset by sales volume decreases of 1% during the current three month period.

~~Natural~~Commodity ~~gas~~Price ~~and~~Risk oil sales for the 2010 third quarter remained substantially unchanged at $0.3 million compared to the prior year third quarter. This revenue stability was primarily a reflection of the decline in production volumes of 17%Management, which was substantially offset by a higher average sales price per Mcfe of 22%. Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $5.33 for the current year quarter compared to $4.38 for the same quarter a year ago.Net

The Partnership ~~expects~~uses various derivative instruments to ~~experience~~manage ~~declines~~fluctuations in ~~both~~ natural gas and crude oil ~~production~~prices. The ~~volumes~~Partnership ~~over~~has in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of the ~~wells~~Partnership’s ~~life~~estimated ~~cycles~~natural ~~until~~gas ~~such~~and ~~time~~crude ~~that~~oil production. Because the Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership’s ~~Codell~~derivative ~~formation~~instruments, ~~Wattenberg~~the ~~Field~~Partnership ~~wells~~ultimately ~~are~~realizes ~~successfully~~a ~~recompleted. Subsequent~~price related to ~~this~~its ~~additional~~collars ~~Codell~~of ~~formation~~no ~~development~~less than the floor and no more than the ceiling and, ~~production~~for ~~will~~the ~~once~~Partnership’s ~~again~~commodity beswaps, ~~expected~~the Partnership ultimately realizes the fixed price related to ~~decline~~its swaps.

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

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

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices. The CIG Index, and other indices for production delivered to Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in the last year and is lower than historical variances. This negative differential between NYMEX and CIG averaged $0.72 and $1.16 for the three and nine months ended September 30, 2009, respectively, and narrowed to an average of $0.51 and $0.88 for the three and nine months ended September 30, 2010, respectively.

- 15 -

Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Commodity~~The ~~Price~~following ~~Risk~~table ~~Management~~presents the realized and unrealized derivative gains and losses included in commodity price risk management (loss) gain, ~~Net~~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.

	Three months ended March 31,
Commodity price risk management, net	2011			2010
Realized gain (loss)
Natural gas	$	40,316		$	159,315
Crude oil		(21,756	)		24,904
Total realized gain, net		18,560			184,219

Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(14,697	)		(170,429	)
Unrealized (loss) gain for the period		(59,269	)		448,235
Total unrealized (loss) gain, net		(73,966	)		277,806
Commodity price risk management (loss) gain, net	$	(55,406	)	$	462,025

~~The~~Three ~~following~~months ~~table~~ended ~~presents~~March ~~the~~31, ~~realized~~2011 ~~and~~as ~~unrealized~~compared ~~derivative~~to ~~gains~~three ~~and~~months ~~losses~~ended ~~included~~March ~~in commodity price risk management gain (loss)~~31, ~~net.~~2010

	Three months ended September 30,						Nine months ended September 30,
Commodity price risk management gain (loss), net	2010			2009			2010			2009
Realized gain
Natural Gas	$	6,841		$	156,805		$	165,334		$	594,077
Oil		30,119			43,983			81,640			196,008
Total realized gain, net		36,960			200,788			246,974			790,085
Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(15,998	)		(201,615	)		(58,800	)		(636,972	)
Unrealized gain (loss) for the period		310,602			(232,919	)		761,279			(744,782	)
Total unrealized gain (loss), net		294,604			(434,534	)		702,479			(1,381,754	)
Commodity price risk management gain (loss), net	$	331,564		$	(233,746	)	$	949,453		$	(591,669	)

Realized gains recognized in the three months ended March 31, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership’s natural gas derivative positions. Realized gains on natural gas settlements were $76,000 for the three months ended March 31, 2011. These gains were offset in part by a $36,000 loss on the Partnership’s CIG basis protection swaps as the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions. The Partnership also realized a $22,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized losses during the three months ended March 31, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership’s open positions. The significant shift upward in the crude oil curve resulted in an unrealized loss of $39,000 during the three months ended March 31, 2011. Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of $20,000.

~~Nine~~During the three months ended ~~September~~March 3031, 2010, the Partnership recorded realized gains of $184,000 as a result of natural gas and crude oil spot prices being lower at settlement compared to ~~nine~~the respective strike price. During the three months ended ~~September~~March 3031, ~~2009~~2010, the Partnership recorded unrealized gains of $448,000, of which $541,000 was related to the Partnership’s natural gas and crude oil positions, partially offset by unrealized losses on the Partnership’s CIG basis protection swaps of $93,000 as the forward basis differential between NYMEX and CIG had continued to narrow.

The realized derivative gains for the 2010 nine month period were approximately $0.2 million. These realized gains were primarily a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG narrowing and being less than the strike price of the derivative position. For the 2010 nine month period, realized gains related to the Partnership’s commodity positions were approximately $0.2 million. Unrealized gains for the 2010 nine month period were due primarily to a downward shift in the natural gas and oil forward curves, offset by unrealized losses due to the basis differential between NYMEX and CIG narrowing and being less than the strike price of the derivative position. Unrealized gains on the Partnership’s commodity positions for the 2010 nine month period were $0.8 million.

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

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Three~~The ~~months~~following ~~ended~~table ~~September~~presents ~~30,~~the ~~2010~~Partnership’s asderivative ~~compared~~positions toin ~~three~~effect ~~months~~as ~~ended~~of ~~September~~March 3031, ~~2009~~2011.

The Partnership’s realized gains are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG narrowing and being less than the strike price of the derivative position. For the quarter, realized gains of $0.1 million related to the Partnership’s commodity positions were offset by realized losses of approximately $0.1 million on the Partnership’s basis position. For the 2010 quarter, the unrealized gains of $0.3 million were primarily related to the natural gas positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential. Unrealized gains on the Partnership’s commodity positions for the 2010 third quarter were $0.3 million, which were partially offset by unrealized losses on the Partnership’s basis position.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-MMbtu(1))		Weighted Average Contract Price				Quantity (Gas-MMbtu(1) Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-MMbtu(1))		Weighted Average Contract Price			Fair Value at March 31, 2011(2)
Commodity/ Index	Quantity (Gas-MMbtu(1))		Floors		Ceilings		Quantity (Gas-MMbtu(1) Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-MMbtu(1))		Weighted Average Contract Price			Fair Value at March 31, 2011(2)

Natural Gas
NYMEX
04/01 - 06/30/2011		-	$	-	$	-		44,460	$	6.78		44,460	$	(1.88	)	$	43,143
07/01 - 09/30/2011		-		-		-		43,985		6.73		43,985		(1.88	)		32,261
10/01 - 12/31/2011		-		-		-		42,939		6.78		42,939		(1.88	)		23,307
01/01 - 03/31/2012		2,527		6.00		8.27		39,053		6.98		41,581		(1.88	)		13,656
04/01 - 12/31/2012		5,237		6.00		8.27		115,789		6.98		121,026		(1.88	)		59,691
2013		-		-		-		149,879		7.12		149,877		(1.88	)		42,608
Total Natural Gas		7,764						436,105				443,868					214,666

Crude Oil
NYMEX
04/01 - 06/30/2011		-		-		-		954		70.75		-		-			(33,789	)
07/01 - 09/30/2011		-		-		-		968		70.75		-		-			(35,009	)
10/01 - 12/31/2011		-		-		-		992		70.75		-		-			(35,842	)
Total Crude Oil		-						2,914				-					(104,640	)

Total Natural Gas and Crude Oil																$	110,026

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

Natural Gas and Oil Sales Derivative Instruments. The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices. The Partnership has in place a series of collars, fixed-price swaps and a basis swap on a portion of the Partnership’s natural gas and oil production. See Note 5, Derivative Financial Instruments to the Partnership’s financial statements included in the 2009 Form 10-K for an additional discussion on how each derivative type impacts the Partnership’s cash flows.

The following table presents the Partnership’s derivative positions in effect as of September 30, 2010.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/	Quantity		Weighted Average Contract Price				Quantity (Gas-Mmbtu(1)		Weighted Average		Quantity		Weighted Average			Fair Value at
Index	(Gas-Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Contract Price		(Gas-Mmbtu(1))		Contract Price			September 30, 2010(2)
Natural Gas
CIG
10/01 - 12/31/2010		14,956	$	4.75	$	9.45		-	$	-		-	$	-		$	16,658
01/01 - 03/31/2011		22,434		4.75		9.45		-		-		-		-			20,820
NYMEX
10/01 - 12/31/2010		3,781		5.75		8.30		28,130		6.15		32,406		(1.88	)		23,178
01/01 - 03/31/2011		5,156		5.75		8.30		17,271		6.84		22,427		(1.88	)		18,925
04/01 - 06/30/2011		-		-		-		44,460		6.78		44,460		(1.88	)		52,919
07/01 - 09/30/2011		-		-		-		43,985		6.73		43,985		(1.88	)		43,153
10/01 - 12/31/2011		-		-		-		42,939		6.79		42,939		(1.88	)		26,988
2012-2013		7,764		6.00		8.27		304,721		7.05		312,484		(1.88	)		158,626
Total Natural Gas		54,091						481,506				498,701					361,267
Oil
NYMEX
10/01 - 12/31/2010		-		-		-		1,798		92.96		-		-			21,013
01/01 - 03/31/2011		-		-		-		930		70.75		-		-			(11,159	)
04/01 - 06/30/2011		-		-		-		954		70.75		-		-			(12,486	)
07/01 - 09/30/2011		-		-		-		968		70.75		-		-			(13,440	)
10/01 - 12/31/2011		-		-		-		992		70.75		-		-			(14,440	)
Total Oil		-						5,642				-					(30,512	)
Total Natural Gas and Oil																$	330,755

(1)

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

(2) Approximately 81% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3),; see Note 4, Fair Value ~~Measurements~~of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.

Natural Gas, NGLs and Crude Oil Production Costs

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

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

Production and operating costs per Mcfe declined to $2.52 during the current period compared to $6.46 for the prior year period due to a decrease in environmental charges in 2011 compared to 2010. Current period production and operating costs decreased by approximately $259,000, primarily due to first quarter 2010 charges for environmental remediation projects at three of the Partnership’s wells for approximately $220,000.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Natural Gas and Oil Production Costs

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

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

For the nine months ended September 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 20% due to normal production declines for this stage in the wells’ production life cycle, production reductions that resulted from well equipment or operational issues at some Wattenberg Field wells and lower Grand Valley well performance due to operational constraints and well optimization efforts.

Production and operating costs increased by approximately $0.3 million for the 2010 nine month period compared to the prior year period due primarily to environmental remediation activities at three Partnership well pads involving seven Partnership wells. Production costs were also higher during the 2010 period as per well operations fees charged by the Managing General Partner escalated, consistent with the terms of the D&O Agreement. Production volume-associated reductions in production taxes, natural gas transportation and lease operating expenses partially offset the environmental and well operating expense increases. Production and operating costs per Mcfe were $4.88 for the nine months ended September 30, 2010 compared to $2.29 for the comparable period in 2009.

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

For the quarter ended September 30, 2010 compared to the same period in 2009, natural gas and oil production on an energy equivalency-basis, decreased 17%, primarily as a result of the Partnership wells’ expected normally-occurring production life-cycle declines and the Wattenberg Field well performance and Grand Valley well optimization efforts, previously noted.

Production and operating costs decreased slightly for the Quarter ended September 30, 2010 as compared to the same period in 2009. Production and operating costs per Mcfe were $2.54 and $2.35 for the quarter ended September 30, 2010 and 2009, respectively.

Direct Costs−General and Administrative

~~Nine~~Three months ended ~~September~~March 3031, ~~2010~~2011 as compared to ~~nine~~three months ended ~~September~~March 3031, ~~2009~~2010

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs increased during the ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011, compared to the same period in ~~2009~~2010, by approximately $~~0.1~~194,000 ~~million~~ principally due to increased fees for ~~professional services related to~~ the ~~Partnership’s~~above ~~SEC~~referenced ~~reporting~~professional ~~compliance efforts previously described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Partnership Operating Results Overview~~services.

Depreciation, Depletion and Amortization

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

The DD&A expense rate per Mcfe decreased to $3.44 for the 2011 three month period, compared to $4.42 during the same period in 2010. The decrease in the per Mcfe rates for the 2011 period compared to the 2010 period is partially due to the fourth quarter 2010 impairment of the Partnership’s Grand Valley Field. Additionally the effect of the upward revision in the Partnership’s proved developed producing natural gas, NGLs and crude oil reserves particularly in the Wattenberg Field as of December 31, 2010, resulted in a decrease in the per Mcfe rates. The production declines, noted in previous sections, contributed to the decreased DD&A expense of approximately $73,000 for the 2011 three month period compared to the same period in 2010.

Financial Condition, Liquidity and Capital Resources

The Partnership’s primary sources of cash for the three months ended March 31, 2011 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. Any future withholdings would provide the funding for planned Wattenberg Field refracturing and recompletion costs to be incurred during 2012, and thereafter and are expected to decrease distributoins from historical levels.

Fluctuations in the Partnership’s operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of March 31, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 100% of the expected natural gas production and 56% of expected crude oil production for the remainder of 2011, at an average price of $4.88 per Mcf and $70.75 per Bbl, respectively. The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. Natural gas, NGLs and crude oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2011 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the additional Codell formation development activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Codell Formation Development Plan.

- 18 -

Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Three~~Working ~~months ended September 30, 2010 as compared to three months ended September 30, 2009~~Capital

~~Direct~~The ~~costs~~Partnership –had ~~general~~negative ~~and~~working ~~administrative~~capital ~~consist primarily~~ of ~~professional~~approximately ~~fees~~$0.3 ~~for~~million ~~financial~~at ~~statement~~both ~~audits~~March 31, ~~income~~2011 ~~tax~~and ~~return~~December ~~preparation~~31, ~~independent~~2010. The ~~engineer~~Partnership’s ~~reserve~~working ~~reports~~capital deficit remained unchanged as net cash provided by operations was used to fund investing activities and ~~legal~~for ~~matters~~cash distributions to the Partners. ~~Direct~~This ~~costs~~deficit ~~increased~~arose ~~during~~in the ~~three~~fourth ~~months~~quarter ~~ended~~of ~~September~~2010 ~~30,~~due ~~2010,~~primarily ~~compared~~to the increase to “Direct costs – general and administrative” resulting from the ~~same~~Partnership’s ~~period~~SEC compliance effort. These costs were in ~~2009,~~excess byof ~~approximately~~cash ~~$0.1~~provided ~~million~~by ~~principally~~operating ~~due~~activities toduring ~~increased~~that ~~fees~~period ~~for~~and ~~professional~~were ~~services,~~paid ~~for~~by the ~~reasons~~Managing ~~noted~~General ~~above~~Partner and remain unpaid by the Partnership.

~~Depreciation,~~Working ~~Depletion~~capital is expected to fluctuate by increasing during periods of Additional Codell Formation Development Plan funding and ~~Amortization~~by decreasing during periods when payments are made for refracturing or recompletions.

~~DD&A~~Cash expense related to natural gas and oil properties is directly related to production volumes for the period. For the quarter ended September 30, 2009, the Partnership’s natural gas and oil economically producible reserve quantities were determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2008. Upon adoption, in the fourth quarter of 2009, of the SEC’s final rule regarding the modernization of oil and gas reporting, the Partnership changed to a valuation price determined by the 12-month average of the first-day-of-the-month price during each month of 2009.Flows

~~Nine~~Cash ~~months~~Flows ~~ended~~From ~~September~~Operating ~~30, 2010 as compared to nine months ended September 30, 2009~~Activities

The ~~DD&A~~Partnership’s ~~expense~~cash ~~rate~~flows ~~per~~provided ~~Mcfe~~by ~~increased~~operating toactivities ~~$4.60~~is ~~for~~primarily ~~the~~impacted ~~2010~~by ~~nine~~commodity ~~month period~~prices, ~~compared to $3.65 during the same period in 2009. The increase in the per Mcfe rates for the 2010 period compared to the 2009 period is due to the changing~~ production ~~mix~~volumes, ~~between~~realized ~~the~~gains ~~Partnership’s Wattenberg~~ and ~~Grand~~losses ~~Valley~~from ~~Fields,~~its ~~which~~derivative ~~have significantly different DD&A rates~~positions, inoperating ~~addition~~costs toand ~~the~~general ~~effect of the downward revision in the Partnership’s proved developed producing natural gas~~ and ~~oil~~administrative ~~reserves at December 31, 2009, as calculated by the respective methodologies described above~~expenses. ~~The~~See ~~increased~~Results ~~DD&A~~of ~~expense~~Operations ~~rate,~~above ~~partially~~for ~~offset~~an byadditional ~~the~~discussion ~~effect~~ of the ~~production~~key ~~declines~~drivers ~~noted~~of incash ~~previous~~flows ~~sections,~~provided ~~resulted~~by inoperating ~~the DD&A expense remaining substantially unchanged at $0~~activities.~~8 million for the 2010 nine month period compared to the same 2009 period.~~

~~Three~~Natural ~~months~~gas, ~~ended~~NGLs ~~September~~and 30crude oil prices exhibit a high degree of volatility. These price variations have a material impact on the Partnership’s financial results. Natural gas and NGLs prices vary by region and locality, ~~2010~~depending asupon ~~compared~~the distance to ~~three~~markets, ~~months~~the ~~ended~~availability ~~September~~of 30pipeline capacity and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply situations from time to time. Like most producers in the region, ~~2009~~the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership’s control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The ~~DD&A~~price ~~expense~~at ~~rate~~which ~~per~~PDC ~~Mcfe~~markets ~~increased~~the tonatural ~~$4.68~~gas ~~for~~produced in the ~~2010~~Rocky ~~three~~Mountain ~~month~~Region ~~period,~~by ~~compared~~the toPartnership ~~$3.68~~is ~~during~~based ~~the~~on ~~same~~a ~~period~~market inbasket ~~2009. The~~of ~~increase~~prices, inwhich ~~the~~primarily ~~per~~includes ~~Mcfe~~natural ~~rates~~gas ~~for~~sold ~~the~~at ~~2010~~CIG ~~period~~prices ~~compared~~with toa ~~the~~portion ~~2009~~sold ~~period~~at isMid-Continent, ~~due~~San toJuan ~~the~~Basin, ~~changing~~Southern ~~production~~California ~~mix~~or ~~between~~other ~~the~~nearby ~~Partnership’s~~region ~~Wattenberg~~prices. The ~~and~~CIG ~~Grand Valley Fields~~Index, ~~which~~and ~~have~~other ~~significantly~~indices ~~different~~for ~~DD&A~~production ~~rates,~~delivered into ~~addition~~other toRocky ~~the~~Mountain ~~effect~~pipelines, ofhave ~~the~~historically ~~downward~~been ~~revision~~less inthan the ~~Partnership’s~~price ~~proved~~received ~~developed~~for ~~producing~~ natural gas ~~and~~produced ~~oil~~in ~~reserves~~the ateastern ~~December 31~~regions, ~~2009,~~which asis ~~calculated~~primarily byNew ~~the~~York ~~respective~~Mercantile ~~methodologies~~Exchange, ~~described~~or ~~above~~NYMEX, based. ~~The~~This ~~increased~~negative ~~DD&A~~differential ~~expense~~has ~~rate,~~narrowed ~~partially~~over ~~offset by~~ the ~~effect~~last offew ~~the~~years ~~production~~and ~~declines~~is ~~noted~~lower inthan ~~previous~~historical ~~sections,~~variances. The ~~resulted~~negative indifferential ~~the~~of ~~DD&A~~CIG ~~expense~~relative ~~remaining~~to ~~substantially~~NYMEX ~~unchanged~~averaged at $0.328 ~~million~~and $0.16 for the ~~2010~~ three ~~month~~months ~~period~~ended ~~compared~~March to31, ~~the~~2011 ~~same~~and ~~2009~~2010, ~~period~~respectively.

Capital Resources and Liquidity

The Partnership’s primary sources of cash for both the three and the nine months ended September 30, 2010 were from funds provided by operating activities which include the sale of natural gas and oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold economic hedges for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of September 30, 2010, the Partnership had natural gas and oil derivative positions in place covering 99% of the expected natural gas production and 67% of expected oil production for the remainder of 2010, at an average price of $4.37 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.

- 19 -

Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~The~~Net ~~Partnership’s~~cash ~~future~~provided ~~operations~~by ~~are~~operating ~~expected to be conducted with available funds and revenues generated from natural gas and oil production~~ activities ~~and~~was ~~commodity~~approximately ~~gains~~$29,000 iffor ~~any. Natural gas and oil production from~~ the ~~Partnership’s~~three ~~existing~~months ~~properties~~ended ~~are~~March ~~generally~~31, ~~expected to continue a gradual decline in the rate of production over the remaining lives of the wells. Therefore~~2011, ~~the~~compared ~~Partnership~~to ~~anticipates~~approximately ~~a lower annual level of natural gas and oil production and~~$472,000 infor the ~~absence~~comparable ofperiod ~~significant~~in ~~price increases or successful additional Codell formation development, lower revenues~~2010. The ~~Partnership~~approximately ~~also~~$443,000 ~~expects cash flows from operations to decline if commodity prices remain at current levels or~~ decrease in ~~the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced~~ cash ~~distributions~~provided toby ~~the~~operating ~~Managing~~activities ~~General~~was ~~Partner~~due ~~and~~primarily ~~Investor Partners through the remainder of 2010 and beyond, and may substantially reduce or restrict the Partnership’s ability~~ to ~~participate in~~ the refracturing and recompletion activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Additional Codell Formation Development Plan.following:

~~Working~~· ~~Capital~~A decrease in natural gas, NGLs and crude oil sales receipts of $100,000, or 22%,

~~The~~· ~~Partnership~~A ~~had~~decrease ~~working~~in ~~capital~~commodity ofprice ~~$0.1~~risk ~~million~~management atrealized ~~September~~gains ~~30,~~receipts ~~2010 compared to working capital~~ of $~~0.4~~154,000, ~~million~~or ~~at December 31~~73%, ~~2009. This decrease of approximately $0.3 million was primarily due to the following changes in accounts receivable~~ and ~~payable balances:~~

· ~~Natural~~An ~~gas~~increase ~~and~~in ~~oil~~production ~~receivables~~costs ~~decreased~~and bydirect ~~$0.1~~costs ~~million~~– asgeneral ofand ~~September~~administrative ~~30,~~payments ~~2010~~of ~~compared to December 31~~$195, ~~2009~~000.

· Realized derivative gains receivables decreased by $0.1 million as of September 30, 2010 compared to December 31, 2009.

· Net short-term unrealized derivative gains receivable increased by approximately $0.1 million as of September 30, 2010 compared to December 31, 2009.

· Due to the Managing General Partner-other payable, excluding natural gas and oil sales received from third parties and realized derivative gains, increased by approximately $0.2 million as of September 30, 2010 compared to December 31, 2009.

Working capital, 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 the first quarter of 2011. 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 percentage of Partnership ownership pro-rata basis, which excludes the Performance Standard Obligation modifications to the Partnership’s distributable cash flow allocation that is more fully described below. 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.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Cash Flows

Cash Flows From Operating Activities

Net cash provided by operating activities was $0.7 million for the nine months ended September 30, 2010, compared to approximately $2.1 million for the comparable period in 2009. The approximately $1.4 million decrease in cash provided by operating activities was due primarily to the following:

· A decrease in commodity price risk management realized gains receipts of $0.6 million, or 61% accompanied by increases in natural gas and oil production costs of $0.4 million, or 71%, and in direct costs – general and administrative of $0.1 million; and

· A decrease in Due to Managing General Partner-other, net, receipts of approximately $0.3 million, excluding natural gas and oil sales received from third parties and realized derivative gains.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts totaled approximately $518,000 and $445,000 for the ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011 and ~~2009~~2010, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in July 2003 and has distributed $20.67 million through ~~September~~March 3031, ~~2010~~2011. The table below presents ~~the~~ cash distributions to the Partnership’s investors. Managing General Partner ~~and~~distributions ~~Investor~~include ~~Partners,~~amounts ~~including~~distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership. Investor Partner distributions ~~relating~~include toamounts ~~limited~~distributed ~~partnership~~to ~~units~~Investor ~~repurchased,~~Partners for their 80% ownership share in the ~~periods~~Partnership ~~described~~and include amounts distributed to PDC for limited partnership units repurchased.

Three months ended September 30,	Managing General Partner Distributions		Investor Partners Distributions			Total Distributions
Quarter ended	Managing General Partner			Investor Partners			Total
2010	$ (6,930)		$ 19,065			$ 12,135
March 31,	Distributions			Distributions			Distributions
2009	$ 161,648		$ 798,012			$ 959,660
2011	$	2,073		$	18,481		$	20,554
2010	$	50,759		$	415,502		$	466,261

Nine months ended September 30,	Managing General Partner Distributions	Investor Partners Distributions	Total Distributions
2010	$ 55,667	$ 595,930	$ 651,597
2009	$ 318,759	$ 1,713,114	$ 2,031,873

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

~~The~~Beginning ~~decrease~~ in ~~total~~April ~~distributions~~2009, when the average Investor Partner’s annual rate of return fell below 12.8%, the Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for ~~both~~distribution, pursuant to the ~~three~~Performance ~~months~~Standard Obligation outlined in Section 4.02 of the Agreement. Distributions paid to the Managing General Partner were reduced and distributions to the ~~nine~~Investor ~~months~~Partners were increased, by $2,038 and $42,494 for the three month periods ended ~~September~~March 3031, 2011 and 2010, respectively, as ~~compared~~a result of the Preferred Cash Distribution made under the terms of Section 4.02. Because of the expected production declines related to the ~~same~~Partnership’s ~~periods~~mature innatural ~~2009~~gas and oil operations, ~~were~~the ~~primarily~~Managing ~~due~~General Partner believes performance obligation allocation rate modifications are likely to ~~the~~continue ~~significant~~until ~~decrease~~June in2013, ~~cash~~when ~~flows~~the ~~from~~provision ~~operating~~expires ~~activities~~under ~~for~~the ~~these~~terms ~~two~~of ~~periods~~the Agreement.

~~Beginning~~- in20 ~~April 2009 when the average Investor Partner annual rate of return fell below 12.8%, the Partnership began to modify the standard ownership~~-~~based~~ pro-rata allocation of Partnership cash available for distribution, pursuant to the Performance Standard Obligation outlined in Section 4.02 of the Agreement. For the nine months ended September 30, 2010 and 2009, distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased, by $74,653 and $87,614, respectively, as a result of the Preferred Cash Distribution made under the terms of this provision. Because of the expected production declines related to the Partnership’s mature natural gas and oil operations, the Managing General Partner believes performance obligation allocation rate modifications are likely to continue until June 2013, when the provision expires under the terms of the Agreement.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Off-Balance Sheet Arrangements

As of March 31, 2011, the Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on the Partnership’s financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

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

Recent Accounting Standards

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

Critical Accounting Policies and Estimates

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

There have been no ~~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~~2010 Form 10-K, such policies include revenue recognition, derivatives instruments, fair value measurements, natural gas and oil properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties.

Off-Balance Sheet Arrangements

Currently, the Partnership does not have any off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of ~~September~~March 3031, ~~2010~~2011, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to ~~Securities~~ Exchange Act ~~Rule~~Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’s ~~Disclosure~~disclosure ~~Committee~~committee in an effort to ensure that information required to be disclosed in the SEC reports that wethe ~~file~~Partnership files or ~~submit~~submits under the Exchange Act ~~are~~is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required ~~financial~~ disclosure.

- 2221 -

Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Based on the results of this evaluation, the Managing General Partner’s Chief Executive Officer and the Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of ~~September~~March 3031, ~~2010~~2011.

(b) Changes in Internal Control over Financial Reporting

During the three months ended March 31, 2011, PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the ~~Securities~~ Exchange Act ~~of 1934~~) ~~during the quarter ended September 30, 2010,~~ that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

~~Information~~ Neither ~~regarding~~ the ~~Registrant’s~~Partnership ~~legal~~nor ~~proceedings~~PDC, ~~can~~in beits ~~found~~capacity inas ~~Note~~the 6,Managing ~~Commitments~~General ~~and~~Partner ~~Contingencies~~of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership’s ~~accompanying~~business, ~~unaudited~~financial ~~condensed~~condition, ~~financial~~results ~~statements~~of operations or liquidity.

Item 1A. Risk Factors

Not applicable.

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

Unit Repurchase Program: Beginning July 2006, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request ~~that~~ the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

The following table presents information about the Managing General Partner’s limited partner unit repurchases during the three months ended ~~September~~March 3031, ~~2010~~2011.

Period	Total Number of Units Repurchased		Average Price Paid per Unit
July 1−31, 2010		0.50	$	2,200
January 1−31, 2011		0.25	$	1,980
August 1−31, 2010		-		-
February 1−28, 2011		2.50		1,538
September 1−30, 2010		-		-
March 1−31, 2011		1.25		940
Total third quarter Unit Repurchase Program repurchases		0.50
Total first quarter Unit Repurchase Program repurchases		4.00

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6. Exhibits Index

~~(a)~~ The ~~Exhibit~~exhibits ~~Index~~presented below are in addition to those presented in the Partnership’s Form 10-K.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

3.1

Limited Partnership Agreement

10-K

000-50226

3.1

10/07/2010

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.

3.2

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

10-K

000-50226

3.2

10/07/2010

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.

10.1

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

10-K

000-50226

10.1

10/07/2010

32.1

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

31.1

31.2

32.1

- 24 -

Index

PDC 2002-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 2002-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)

~~January~~May 2710, 2011

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

Signature	Title	Date
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	~~January~~May 2710, 2011
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~January~~May 2710, 2011
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~January~~May 2710, 2011
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)

- 25 -

Filing Compare · PDC 2002 D LTD PARTNERSHIP