CONFORMED COPY

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

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

FORM 10-Q

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

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

For the period ended March 31, 2005

[£ TRANSITION ]REPORT ~~Transition Report~~PURSUANT ~~Pursuant~~TO toSECTION ~~Section~~ 13 ofOR 15(d) ofOF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

~~the~~Commission ~~Securities Exchange~~File ~~Act of 1934~~Number 000-50226

~~For~~PDC ~~the~~2002-D ~~transition period~~Limited ~~from to~~Partnership

~~Commission~~(Exact ~~file number~~name ~~000-50226~~of registrant as specified in its charter)

I.R.S. Employer Identification Number 04-3726919

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) and (2) has been subject to such filing requirements for the past 90 days.

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 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 T

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

As of September 30, 2010 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)

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

Bridgeport, WV 26330

		Page
PART I – FINANCIAL INFORMATION

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

PART II – OTHER INFORMATION

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

	SIGNATURES	25

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

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

~~Indicate~~This byperiodic ~~check~~report ~~mark~~contains ~~whether~~“forward-looking statements” within the ~~registrant~~meaning isof ~~an accelerated~~Section ~~filer~~27A of the Securities Act of 1933 (asthe ~~definition~~“Securities inAct”) ~~Rule~~and ~~12b-2~~Section 21E of the Securities Exchange Act. of 1934 (“Exchange Act”) ~~Yes No XX~~ regarding PDC 2002-D Limited Partnership’s (the “Partnership” or the “Registrant”) business, financial condition, results of operations and prospects.

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

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

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

changes in estimates of proved reserves;

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

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

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

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

future production and additional Codell formation development costs;

the availability of Partnership future cash flows for investor distributions or funding of additional Codell formation development activities;

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

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

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

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

the effect of natural gas and oil derivatives activities;

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

conditions in the capital markets; and

losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report, the Partnership’s annual reports on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission, or SEC, on 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.

- 1 -

Index

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements (unaudited)

PDC 2002-D Limited Partnership

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.

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Index

PDC 2002-D Limited Partnership

Condensed Statements of Operations

(unaudited)

	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 accompanying notes to unaudited condensed financial statements.

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Index

PDC 2002-D Limited Partnership

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.

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Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2002-D Limited Partnership (the “Partnership”) was organized as a limited partnership on June 3, 2002 in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties. Upon completion of the sale of Partnership units on December 31, 2002, the Partnership was funded and commenced its business operations. The Partnership owns natural gas and oil wells located in Colorado and from the wells, the Partnership produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 33.15 units of limited partner interests and 1,422.11 units of additional general partner interests at $20,000 per unit. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a Nevada Corporation that now conducts business under the name “PDC Energy,” is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner” or “PDC”) and has a 20% Managing General Partner ownership in the Partnership. Upon completion of the drilling phase of the Partnership's wells, all additional general partners’ units were converted into units of limited partner interests and thereafter became limited partners of the Partnership.

Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 20% to the Managing General Partner. Beginning in April 2009 when the conditions of the obligation arose and expiring upon the termination of Performance Standard Obligation provision in June 2013, the Partnership modified the allocation rate of all items of profit and loss and resulting cash available for distribution from that described above, between the Managing General Partner and the Investor Partners, pursuant to Section 4.02 Distributions, of the Partnership 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. For more information concerning the Performance Standard Obligation, see Note 6, Partners’ Equity and Cash Distributions to the Partnership financial statements that accompany the 2009 Form 10-K.

As of September 30, 2010, there were 1,041 Investor Partners. As of September 30, 2010, the Managing General Partner has repurchased 137.13 units of the total 1,455.26 outstanding units of Partnership interests from Investor Partners at an average price of $5,533 per unit and, as a result, participates in the sharing of revenues, costs and cash distributions as both an investor partner and as the Managing General Partner.

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

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

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Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

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

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

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

Internal Control over Financial Reporting in Exchange Act Periodic Reports

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

Note 3−Transactions with Managing General Partner and Affiliates

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

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Index

PDC 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.

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Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

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

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

As of December 31, 2009
Assets:
Commodity based derivatives	$	210,848		$	230,659		$	441,507
Total assets		210,848			230,659			441,507

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

	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

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

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Index

PDC 2002-D LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

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

Note 5−Derivative Financial Instruments

As of September 30, 2010, 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 535,597 MMbtu of natural gas and 5,642 Bbls of oil. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

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

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

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	389,512	$	234,618

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		649,460		206,889


Total Derivative Assets			$	1,038,972	$	441,507

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	37,085	$	14,362

	Basis protection contracts	Due to Managing General Partner-derivatives		192,848		186,479

	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		14,440		57,931

	Basis protection contracts	Due to Managing General Partner-derivatives		463,844		554,459

Total Derivative Liabilities			$	708,217	$	813,231

(1)

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

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three and 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 30, 2010

(unaudited)

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

Note 6−Commitments and Contingencies

Environmental

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

In December 2008, the Managing General Partner received a Notice of Violation/Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance region of Colorado. Operating expenses, including this fine, if any, are allocated among the users of the road based upon their respective usage. The Partnership has 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)

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

PART I - FINANCIAL INFORMATION			Page No.
Item 1.1.	Financial Statements
		Balance Sheets - March 31, 2005 (unaudited) and December 31, 2004	1
		Statements of Operations - Three Months Ended March 31, 2005 and 2004 (unaudited)	2
		Statement of Partners' Equity and Comprehensive Income (Loss) - Three Months Ended March 31, 2005 (unaudited)	3
		Statements of Cash Flows- Three Months Ended March 31, 2005 and 2004 (unaudited)	4
		Notes to Financial Statements	5
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations	6
Item 3.		Quantitative and Qualitative Disclosure About Market Rate Risk	9
Item 4.		Controls and Procedures	10
PART II OTHER INFORMATION
Item 1.		Legal Proceedings	11
Item 6.		Exhibits	11

Partnership Overview

PDC 2002-D Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in December 2002 and operates 36 gross (32.3 net) productive wells located in the Rocky Mountain Region in the state of Colorado. Of the Partnership’s total well count, 35 are producing and one Wattenberg Field well is not producing due to mechanical problems. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

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

In June 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership (collectively, the “2004 partnerships”). PDC serves as the managing general partner of each of the 2004 partnerships. Definitive proxy statements for each of the 2004 partnerships requesting approval for the applicable merger were mailed to the non-affiliated Investor Partners of the 2004 partnerships in early October 2010. Special meetings were held on December 8, 2010, at which the majority of the non-affiliated Investor Partners of each of the 2004 partnerships voted to approve the applicable merger. These mergers were completed on December 17, 2010.

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

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

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

Assets
	2005	2004
	(Unaudited)
Current assets:
Cash	$ 2,305	2,933
Accounts receivable - oil and gas revenues	773,708	911,604
Due from managing general partner	1,467	-
Total current assets	777,480	914,537
Oil and gas properties, successful efforts method	31,667,260	31,667,260
Less accumulated depreciation, depletion
and amortization	6,327,998	5,823,001
	25,339,262	25,844,259
	$26,116,742	26,758,796
Liabilities and Partners' Equity
Current liabilities:
Due to Managing General Partner	$ 300	300
Accrued expenses	88,426	184,582
Total current liabilities	88,726	184,882
Asset retirement obligations	17,411	17,154
Partners' Equity	26,010,605	26,556,760
	$26,116,742	26,758,796

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

~~See~~Additional ~~accompanying~~Codell ~~notes~~formation development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ~~financial~~ten ~~statements~~years after initial well drilling so that well resources are optimally utilized. This additional 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 or refracture the individual wells and to determine the timing of any additional development activity. The timing of the additional development can be affected by the desire to optimize the economic return by recompleting or refracturing the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. On average, the production resulting from PDC's successful Codell recompletions and refracturings have been at modeled economics; however, all recompletions or refracturings have not been economically successful and similar future development 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 or refracturing, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from distributable cash flows.

During the fourth quarter 2010, the Managing General Partner began withholding funds from several of the PDC sponsored partnerships, on a pro-1-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows of the Partnership resulting from current production. The funds retained are necessary for the Partnership to pay for additional Codell formation development costs and will materially reduce, up to 100%, distributable cash flows of the Partnership 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.

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Statements~~Current estimated costs for these well refracturings and recompletions are between $150,000 and $200,000 per activity. This Partnership potentially has 32 additional Codell formation development opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $4.8 million and $6.4 million. The Managing General Partner will continually evaluate the timing of ~~Operations~~ 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.

~~Three~~Implementation ~~Months~~of ~~ended~~the ~~March~~Additional 31Codell Formation Development Plan would reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, ~~2005~~it is possible that the Managing General Partner and ~~2004~~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.

~~(Unaudited)~~Partnership Operating Results Overview

	2005	2004
Revenues:
Sales of oil and gas	$997,590	1,574,114
Interest income	838	653
	998,428	1,574,767
Expenses:
Lifting cost	255,741	324,857
Direct administration cost	257	-
Depreciation, depletion, and amortization	504,997 760,995	717,727 1,042,584
Net income	$ 237,433	532,183
Net income per limited partner unit	$ 131	293

Natural gas and oil sales increased 16% or $0.1 million for the first nine months of 2010 compared to the first nine months of 2009, even though production volumes decreased 20% 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 $5.75 for the current year period compared to $3.98 for the same period a year ago. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $7.11 for the current year nine months from $7.47 for the same prior year period. The decrease was primarily due to realized derivative gains from natural gas and oil sales contributing only $1.36 per Mcfe or $0.2 million to the first nine months of 2010 total revenues as compared to $3.49 per Mcfe or $0.8 million to the nine months of 2009 total revenues.

The Partnership’s combined natural gas and oil production expenses and direct costs−administrative and general, increased by $0.4 million during the 2010 nine month period. Higher production expenditures were primarily due to environmental remediation activities during the current nine month period involving seven Partnership wells at three well pads. See Note 6, Commitments and Contingencies, to the accompanying ~~notes~~unaudited condensed financial statements, included in this report. Higher administrative and general expenses were due to higher fees for audit 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.

-2 13 -

Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

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

(Unaudited)

	Three months ended September 30,							Nine months ended September 30,
	2010		2009		Change			2010		2009		Change
Number of producing wells (end of period)		35		36		(1	)		35		36		(1	)

Production (1)
Natural gas (Mcf)		47,455		56,394		-16	%		145,359		179,321		-19	%
Oil (Bbl)		1,980		2,530		-22	%		6,015		7,811		-23	%
Natural gas equivalents (Mcfe) (2)		59,335		71,574		-17	%		181,449		226,187		-20	%

Natural Gas and Oil Sales
Natural gas	$	177,219	$	160,090		11	%	$	612,797	$	536,623		14	%
Oil		138,853		153,309		-9	%		430,711		363,064		19	%
Total natural gas and oil sales	$	316,072	$	313,399		1	%	$	1,043,508	$	899,687		16	%

Realized Gain on Derivatives, net
Natural gas	$	6,841	$	156,805		-96	%	$	165,334	$	594,077		-72	%
Oil		30,119		43,983		-32	%		81,640		196,008		-58	%
Total realized gain on derivatives, net	$	36,960	$	200,788		-82	%	$	246,974	$	790,085		-69	%

Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	3.73	$	2.84		32	%	$	4.22	$	2.99		41	%
Oil (per Bbl)		70.13		60.60		16	%		71.61		46.48		54	%
Natural gas equivalents (per Mcfe)		5.33		4.38		22	%		5.75		3.98		45	%

Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.88	$	5.62		-31	%	$	5.35	$	6.31		-15	%
Oil (per Bbl)		85.34		77.98		9	%		85.18		71.57		19	%
Natural gas equivalents (per Mcfe)		5.95		7.18		-17	%		7.11		7.47		-5	%

Average Lifting Cost (per Mcfe) (3)	$	2.54	$	2.35		8	%	$	4.88	$	2.29		113	%

Operating costs and expenses
Direct costs - general and administrative	$	104,622	$	587		*		$	111,537	$	15,146		*
Depreciation, depletion and amortization	$	277,745	$	263,284		5	%	$	834,844	$	825,321		1	%

Cash distributions	$	12,135	$	959,660		-99	%	$	651,597	$	2,031,873		-68	%

	Limited Partners	Managing General Partner	Accumulated Other Comprehensive Income (loss)	Total
Balance December 31, 2004	$21,311,343	5,327,837	(82,420)	26,556,760
Distributions to partners	(645,015)	(161,253)	-	(806,268)
Comprehensive income:
Net income	189,946	47,487	-	237,433
Change in fair value of outstanding hedging positions			18,360
Less reclassification adjustments for settled contracts included in net income			4,320
Other comprehensive income			22,680	22,680
Comprehensive income				260,113
Balance March 31, 2005	$20,856,274	5,214,071	(59,740)	26,010,605

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

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

~~-3-~~(1) Production is determined by multiplying the gross production volume of properties in which the Partnership has an interest by the percentage of the leasehold or other property interest the Partnership owns.

(2)

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

(3)

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

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Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Statements~~Definitions used throughout Management’s Discussion and Analysis of ~~Cash Flows~~Financial Condition and Results of Operations:

~~Three~~· ~~Months~~Bbl ~~ended~~– ~~March~~One ~~31,~~barrel ~~2005~~or ~~and~~42 ~~2004~~U.S. gallons liquid volume

~~(Unaudited)~~· MBbl – One thousand barrels

	2005	2004
Cash flows from operating activities:
Net income	$237,433	532,183
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	504,997	717,727
Accretion of asset retirement obligations	257	-
Changes in operating assets and liabilities:
Decrease in accounts receivable - oil and gas revenues	72,426	95,130
Increase in due from managing general partner	(1,467)	-
Decrease in accounts payable	(8,006)	(5,474)
Net cash provided from operating activities	805,640	1,339,566
Cash flows from financing activities:
Distributions to partners	(806,268)	(1,338,912)
Net cash used by financing activities	(806,268)	(1,338,912)
Net (decrease) increase in cash	(628)	654
Cash at beginning of period	2,933	655
Cash at end of period	$ 2,305	1,309

Mcf – One thousand cubic feet

~~See~~· ~~accompanying~~MMcf ~~notes~~– toOne ~~financial~~million ~~statements.~~cubic feet

~~-4-~~· 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 and Oil Sales

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

The $0.1 million, or 16% increase in sales for the 2010 nine month period as compared to the prior year period, was primarily a reflection of the significantly higher average sales price per Mcfe of 45%, 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.

Natural gas and oil revenues increased by 14% and 19%, respectively. The Partnership’s natural gas revenue increase resulted from rising commodity prices per Mcf, of 41%, which were partially offset by lower Partnership natural gas production volumes of 19%. This compares to the slightly higher oil revenue increase in which the rise in commodity prices per Bbl, of 54% was partially offset by the decline in oil production volumes of 23% during the current nine month period.

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

Natural gas and 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%, 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.

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

Natural Gas and Oil Pricing

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

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

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

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

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

Reference is hereby made to PDC 2002-D Limited Partnership's (the Partnership's) Annual Report on Form 10-K for 2004, which contains a summary of significant accounting policies followed by the Partnership in the preparation of its financial statements. These policies were also followed in preparing the quarterly report included herein.

	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	)

~~2. Basis of~~Nine ~~Presentation~~months ended September 30, 2010 as compared to nine months ended September 30, 2009

The ~~Management~~ ofrealized derivative gains for the ~~Partnership~~2010 ~~believes~~nine ~~that~~month ~~all~~period ~~adjustments~~were ~~(consisting~~approximately $0.2 million. These realized gains were primarily a result of ~~only normal~~lower ~~recurring~~natural ~~accruals)~~gas ~~necessary~~and oil spot prices at settlement compared to athe ~~fair~~respective ~~statement~~strike ofprice, offset in part by realized losses due to the ~~results~~basis ofdifferential ~~such periods~~between ~~have~~NYMEX ~~been~~and ~~made. The~~CIG ~~results~~narrowing and being less than the strike price of ~~operations~~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 ~~three~~2010 ~~months~~nine ~~ended~~month ~~March~~period 31were due primarily to a downward shift in the natural gas and oil forward curves, ~~2005~~offset ~~are~~by ~~not~~unrealized ~~necessarily~~losses ~~indicative~~due to the basis differential between NYMEX and CIG narrowing and being less than the strike price of the ~~results~~derivative toposition. Unrealized begains ~~expected~~on the Partnership’s commodity positions for the ~~full year~~2010 nine month period were $0.8 million.

3For 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. ~~Oil~~ Unrealized losses for the period were related to oil swaps, as the forward strip price of oil rebounded during the period, and ~~Gas~~the ~~Properties~~basis position, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

The Partnership follows the successful efforts method of accounting for the cost of exploring for and developing oil and gas reserves. Under this method, costs of development wells, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, and successful exploratory wells are capitalized and amortized on an annual basis to operations by the units-~~of-production~~ ~~method~~16 using estimated proved developed reserves determined at year end by Petroleum Development Corporation's (the Managing General Partner's) petroleum engineers. If a determination is made that an exploratory well has not discovered economically producible reserves, then its costs are expensed as dry hole cost. -

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

4. Revenue Recognition

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

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

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

-5-

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

~~(Unaudited)~~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.

5For 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. ~~Derivative~~ Unrealized ~~Instruments~~losses for the period were primarily related to oil swaps, as the forward strip price of oil rebounded during the period, and ~~Hedging~~the ~~Activities~~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, ~~utilizes~~on ~~commodity~~behalf ~~based~~of ~~derivative~~the ~~instruments~~Partnership asin ~~hedges~~accordance towith ~~manage~~the ~~a portion~~D&O ofAgreement, ~~the~~is ~~Partnership's~~authorized ~~exposure~~to utilize various derivative instruments to ~~price~~manage volatility ~~stemming~~in ~~from~~natural ~~oil~~gas and ~~natural~~ ~~gas~~oil ~~production~~prices. The ~~These~~Partnership ~~instruments~~has ~~consist~~in ofplace ~~CIG~~a ~~(Colorado~~series ~~Interstate Gas~~of ~~Index)~~collars, ~~based~~fixed-price ~~contracts~~swaps ~~for~~and ~~Colorado~~a ~~production,~~basis ~~and~~swap ~~NYMEX~~on ~~traded~~a ~~oil futures~~portion ~~and~~of ~~option~~the ~~contracts~~Partnership’s ~~for~~natural ~~Colorado~~gas and oil production. ~~The~~ See ~~costless~~Note ~~collars and~~5, ~~option~~Derivative ~~contracts~~Financial ~~hedge~~Instruments ~~committed~~to ~~and~~the ~~anticipated~~Partnership’s ~~oil~~financial ~~and~~statements ~~natural~~included ~~gas~~in ~~sales generally~~the ~~forecasted~~2009 toForm ~~occur~~10-K ~~within~~for aan 24additional ~~month~~discussion ~~period. The~~on ~~Partnership does~~how ~~not~~each ~~hold~~derivative ortype ~~issue~~impacts ~~derivatives~~the ~~for~~Partnership’s ~~trading~~cash ~~or speculative purposes~~flows.

~~All~~The ~~derivatives~~following ~~are recognized~~table onpresents the Partnership’s ~~balance sheet at their fair value. On the date the~~ derivative ~~contract~~ ispositions ~~entered~~in ~~into,~~effect ~~the Managing General Partner designates the derivative~~ as ~~either a hedge~~ of aSeptember ~~forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability ("cash flow" hedge)~~30, ~~or a non-hedging derivative~~2010. The Managing General Partner formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash- flow hedges to specific firm commitments. The Managing General Partner also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Partnership discontinues hedge accounting prospectively. No hedging activities were discontinued during 2005 or 2004.

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

	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

By(1) ~~using~~A ~~derivative~~standard ~~financial~~unit ~~instruments to hedge exposures to changes in commodity prices, the Managing General Partner exposes the Partnership to credit risk. Credit risk is the failure~~ of ~~the~~ ~~counterparty~~measure tofor ~~perform the~~natural ~~terms~~gas of(one ~~the~~MMbtu ~~derivative~~equals ~~contract.~~one ~~When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk~~Mcf). ~~The Managing General Partner minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties.~~

~~Item~~ (2~~. Management's~~) ~~Discussion~~Approximately ~~and~~8% ~~Analysis~~of the fair value of ~~Financial~~the ~~Condition~~Partnership’s derivative assets and ~~Results~~ all of ~~Operations~~the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.

~~Liquidity and~~- ~~Capital~~17 ~~Resources~~-

The Partnership was funded on December 31, 2002 with initial Limited and Additional General Partner contributions of $29,105,281 (1,455.26 units) and the Managing General Partner's cash contribution of $6,330,399 in accordance with the Limited Partnership Agreement. After payment of syndication costs of $3,056,055 and a one-time management fee to the Managing General Partner of $727,632 the Partnership had available cash of $31,651,993 for Partnership activities.Index

The Partnership began exploration and development activities subsequent to the funding of the Partnership and completed well drilling activities by December 31, 2003. Thirty-six wells have been drilled, all of which have been completed as producing wells. No additional wells will be drilled.

The Partnership had working capital at March 31, 2005 of $688,754.

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

-6-

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Notes~~Natural toGas ~~Financial Statements~~and Oil Production Costs

~~(Unaudited)~~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.

~~Results of~~Nine ~~Operations~~months ended September 30, 2010 as compared to nine months ended September 30, 2009

~~Three~~For the nine months ended ~~March~~September 3130, ~~2005~~2010 compared ~~with~~to ~~March~~the 31same period in 2009, ~~2004~~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.

~~Oil~~ Production and ~~gas~~operating ~~sales~~costs ~~for~~increased ~~the~~by ~~three~~approximately ~~months ended March 31, 2005 were~~ $~~997,590 compared to $1,574,114 for the three months ended March 31, 2004, a decrease of $576,524 or 37%~~0.3 ~~The~~million ~~volume of natural gas sold~~ for the ~~three~~2010 ~~months~~nine ~~ended~~month ~~March~~period ~~31, 2005, was 136,938 Mcf at an average sales price of $5.54 per Mcf~~ compared to ~~245,269 Mcf at an average price of $4.67 per Mcf for~~ the ~~three~~prior ~~months~~year ~~ended~~period ~~March~~due ~~31,~~primarily ~~2004. The~~to ~~volume~~environmental ofremediation ~~oil~~activities ~~sold~~at ~~for the~~ three ~~months~~Partnership ~~ended~~well ~~March~~pads ~~31,~~involving ~~2005~~seven ~~was~~Partnership ~~5,022 barrels at an average sales price of $47~~wells.45 Production ~~compared~~costs towere ~~12,174~~also ~~barrels~~higher atduring ~~an average price of $35.15 for~~ the ~~three~~2010 ~~months~~period ~~ended~~as ~~March~~per ~~31,~~well ~~2004. The~~operations ~~Lifting~~fees ~~cost~~charged ~~for~~by the ~~three~~Managing ~~months~~General ~~ended~~Partner ~~March 31~~escalated, ~~2005~~consistent ~~was~~with ~~$1.53~~the ~~per~~terms ~~Mcfe~~of ~~compared~~the toD&O $1Agreement.02 Production ~~per~~volume-associated ~~Mcfe~~reductions ~~for~~in ~~the~~production ~~three~~taxes, ~~months~~natural ~~ended~~gas ~~March~~transportation ~~31,~~and ~~2004.~~lease ~~This~~operating ~~increase~~expenses is partially ~~attributed~~offset to the ~~increase~~environmental inand ~~severance~~well ~~and~~operating ~~property~~expense ~~taxes~~increases. ~~The fixed~~ Production ~~costs of operations~~ and ~~well~~operating ~~maintenance~~costs ~~are allocated to lower production volumes, therefore increasing the lifting cost~~ per Mcfe~~. Depreciation, depletion~~ ~~and~~were ~~amortization~~$4.88 for the ~~three~~nine months ended ~~March~~September 3130, ~~2005~~2010 ~~was $504,997~~ compared to $~~717,727 for the three months ended March 31, 2004~~2. ~~While~~29 ~~the Partnership experienced a net income of $237,433 and $532,183~~ for ~~2005 and 2004, respectively, depreciation, depletion and amortization is a non-cash expense and therefore~~ the ~~Partnership~~comparable ~~distributed~~period ~~$806,268~~in ~~and $1,338,912 to the partners for the three months ended March 31, 2005 and 2004, respectively~~2009.

~~The~~Three ~~Partnership's~~months ~~revenue~~ended ~~from~~September ~~oil and gas will be affected by changes in prices. As a result of changes in federal regulations~~30, ~~gas~~ ~~prices~~2010 ~~are~~as ~~highly~~compared ~~dependent on the balance between supply and demand. The Partnership's gas sales prices are subject~~ to ~~increase~~three ~~and~~months ~~decrease~~ended ~~based~~September ~~on various~~30, ~~market sensitive indices.~~2009

~~Critical Accounting~~For ~~Policies~~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.

~~Certain~~Production ~~accounting~~and ~~policies~~operating ~~are~~costs ~~very~~decreased ~~important to~~slightly ~~the~~for ~~portrayal of~~ the ~~Partnership's~~Quarter ~~financial~~ended ~~condition~~September ~~and results of operations and require management's most subjective or complex judgments. In applying those policies~~30, ~~our~~2010 ~~management~~as ~~uses~~compared ~~its judgment~~ to ~~determine~~ the ~~appropriate~~ ~~assumptions~~same toperiod ~~be used~~ in ~~the determination of certain estimates~~2009. ~~Those~~ Production ~~estimates~~and ~~are~~operating ~~based~~costs onper ~~our~~Mcfe ~~historical~~were ~~experience,~~$2.54 ~~our~~and ~~observance~~$2.35 ~~of trends~~for in the ~~industry,~~quarter ~~and~~ended ~~information~~September ~~available from other outside sources~~30, as ~~appropriate.~~2010 ~~The Partnership's critical accounting policies~~ and ~~estimates are~~2009, ~~as follows:~~respectively.

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

~~The Managing~~Nine ~~General~~months ~~Partner~~ended ~~currently~~September ~~uses~~30, ~~the~~2010 ~~"Net-Back"~~as ~~method~~compared ofto ~~accounting~~nine ~~for transportation~~months ~~arrangements~~ended ofSeptember ~~natural~~30, gas sales. The Managing General Partner sells gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the 2009

~~Managing General~~Direct ~~Partner'~~costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s ~~customers~~reserve reports and ~~reflected~~legal matters. Direct costs increased during the nine months ended September 30, 2010, compared to the same period in 2009, by approximately $0.1 million principally due to increased fees for professional services related to the ~~wellhead~~Partnership’s ~~price~~SEC reporting compliance efforts previously described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Partnership Operating Results Overview.

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered in a stock tank, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production. The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under short-~~term~~ ~~purchase~~18 ~~contracts at prices and in accordance with arrangements that are customary in the oil industry.~~ -

~~-7-~~Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

~~(Unaudited)~~Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs increased during the three months ended September 30, 2010, compared to the same period in 2009, by approximately $0.1 million principally due to increased fees for professional services, for the reasons noted above.

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

~~Oil~~DD&A expense related to natural gas and ~~Gas~~oil ~~Properties~~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.

~~Exploration~~Nine ~~and development~~months ~~costs~~ended ~~are~~September ~~accounted~~30, ~~for~~2010 byas ~~the~~compared ~~successful~~to ~~efforts~~nine ~~method.~~months ended September 30, 2009

The ~~Partnership~~DD&A ~~assesses~~expense ~~impairment~~rate ofper ~~capitalized~~Mcfe ~~costs of~~increased ~~proved~~to ~~oil~~$4.60 ~~and~~for ~~gas~~the ~~properties~~2010 bynine ~~comparing~~month ~~net~~period, ~~capitalized~~compared ~~costs~~to $3.65 during the same period in 2009. The increase in the per Mcfe rates for the 2010 period compared to ~~estimated undiscounted~~the ~~future~~2009 ~~cash~~period ~~flows~~is ondue ato ~~field-by-field~~the ~~basis~~changing ~~using~~production ~~expected~~mix ~~prices. Prices~~between ~~utilized~~the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates, in ~~each~~addition ~~year'~~to the effect of the downward revision in the Partnership’s ~~calculation~~proved ~~for~~developed ~~measurement~~producing ~~purposes~~natural gas and ~~expected~~ ~~costs~~oil ~~are~~reserves ~~held~~at ~~constant~~December ~~throughout~~31, ~~the~~2009, ~~estimated~~as ~~life~~calculated ofby the ~~properties~~ respective methodologies described above. The Ifincreased ~~net~~DD&A ~~capitalized~~expense ~~costs~~rate, ~~exceed~~partially ~~undiscounted~~offset ~~future~~by ~~net~~the ~~cash~~effect ~~flow~~of the production declines noted in previous sections, resulted in the ~~measurement~~DD&A ofexpense ~~impairment~~remaining issubstantially ~~based~~unchanged onat ~~estimated~~$0.8 ~~fair~~million ~~value~~for ~~which~~the ~~would consider~~2010 ~~future~~nine ~~discounted~~month ~~cash~~period ~~flows~~compared to the same 2009 period.

~~Property~~Three ~~acquisition~~months ~~costs~~ended ~~are~~September capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered30, ~~such~~2010 ~~costs are expensed~~ as ~~dry holes. Development~~compared ~~costs, including equipment and intangible drilling costs related~~ to ~~both~~three ~~producing~~months ~~wells~~ended ~~and~~September ~~developmental~~30, ~~dry holes are capitalized.~~2009

~~Unproved~~The ~~properties~~DD&A expense rate per Mcfe increased to $4.68 for the 2010 three month period, compared to $3.68 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 between the Partnership’s Wattenberg and ~~leases~~Grand ~~are~~Valley ~~written-off~~Fields, which have significantly different DD&A rates, in addition to the effect of the downward revision in the Partnership’s proved developed producing natural gas and oil reserves at December 31, 2009, as calculated by the respective methodologies described above. The increased DD&A expense ~~when~~ itrate, ispartially ~~determined~~offset ~~that~~by ~~they~~the ~~will~~effect ~~expire~~of the production declines noted in previous sections, resulted in the DD&A expense remaining substantially unchanged at $0.3 million for the 2010 three month period compared to bethe ~~abandoned~~same 2009 period.

~~Costs~~Capital ofResources ~~proved properties, including leasehold acquisitions, exploration~~ and ~~development costs and equipment, are depreciated and depleted by the unit-of-production method based on estimated proved developed oil and gas reserves.~~Liquidity

~~Upon~~The ~~sale~~Partnership’s orprimary ~~retirement~~sources of ~~complete~~cash ~~fields~~for both the three and the nine months ended September 30, 2010 were from funds provided by operating activities which include the sale of ~~depreciable or~~natural ~~depletable~~gas ~~property~~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 ~~book~~Investor ~~value~~Partners ~~thereof~~and PDC, ~~less~~the ~~proceeds~~Managing orGeneral ~~salvage~~Partner. Fluctuations ~~value~~in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, is ~~credited~~in orproduction ~~charged~~volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership attempts to ~~income~~manage this volatility through derivatives. ~~Upon~~ Therefore, ~~sale~~the primary source of athe ~~partial~~Partnership’s ~~unit~~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 ~~property~~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 ~~proceeds~~ ~~are~~Partnership ~~credited~~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 ~~accumulated~~remain ~~depreciation~~substantially below gains realized in 2009 and ~~depletion~~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.

~~Recently Issued~~- ~~Accounting~~19 ~~Pronouncements~~-

~~Asset Retirement Obligations~~Index

On PDC ~~March~~2002-D ~~30,~~LIMITED 2005, the FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN No. 47). This interpretation clarifies that the term "conditional asset retirement obligation" as used in Statement No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 will be effective for the Partnership at the end of the fiscal year ended December 31, 2005. The Partnership has not determined the impact on the Partnership's financial position or results of operations of the application of FIN No. 47.PARTNERSHIP

~~-8-~~(A West Virginia Limited Partnership)

~~PDC~~The ~~2002-D~~Partnership’s ~~LIMITED PARTNERSHIP~~future operations are expected to be conducted with available funds and revenues generated from natural gas and oil production activities and commodity gains, if any. Natural gas and oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining lives of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas and oil production and, in the absence of significant price increases or successful additional Codell formation 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 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.

(AWorking ~~West Virginia Limited Partnership)~~Capital

~~Notes~~The Partnership had working capital of $0.1 million at September 30, 2010 compared to ~~Financial Statements~~working capital of $0.4 million at December 31, 2009. This decrease of approximately $0.3 million was primarily due to the following changes in accounts receivable and payable balances:

~~(Unaudited)~~· Natural gas and oil receivables decreased by $0.1 million as of September 30, 2010 compared to December 31, 2009.

~~Disclosure Regarding~~· ~~Forward~~Realized ~~Looking~~derivative ~~Statements~~gains receivables decreased by $0.1 million as of September 30, 2010 compared to December 31, 2009.

~~This~~· ~~Form~~Net 10short-Qterm ~~contains~~unrealized ~~"forward-looking statements"~~derivative ~~within~~gains ~~the~~receivable ~~meaning~~increased of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in and incorporated by ~~reference~~approximately ~~into this Form 10-Q are forward-looking statements~~$0.1 ~~These~~million ~~forward-looking~~as statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are the Managing General Partner's estimate of ~~the sufficiency~~September ~~of its existing capital sources~~30, ~~its~~2010 ~~ability~~compared to ~~raise~~December ~~additional capital to fund cash requirements for future operations~~31, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, and the operating hazards attendant to the oil and gas business2009. In particular, careful consideration should be given to cautionary statements made in the various reports the Partnership has filed with the Securities and Exchange Commission. The Partnership undertakes no duty to update or revise these forward-looking statements.

~~When used~~· inDue ~~the~~to ~~Form 10-Q,~~ the ~~words,~~Managing ~~"expect,"~~General ~~"anticipate," "intend," "plan," "believe," "seek," "estimate" and similar expressions are intended to identify forward~~Partner-~~looking~~other ~~statements~~payable, ~~although~~excluding ~~not~~natural ~~all~~gas ~~forward-looking statements contain these identifying words. Because these forward-looking statements involve risks~~ and ~~uncertainties,~~oil ~~actual~~sales ~~results~~received ~~could differ materially~~ from ~~those~~third ~~expressed or~~parties ~~implied~~and byrealized ~~these~~derivative ~~forward-looking statements for a number of important reasons~~gains, ~~including~~increased ~~those~~by ~~discussed~~approximately ~~under~~$0.2 ~~"Management's~~million ~~Discussions~~as ~~and Analysis~~ of ~~Financial~~September ~~Condition~~30, ~~and~~2010 ~~Results~~compared ofto ~~Operations"~~December ~~and~~31, ~~elsewhere in this Form 10-Q~~2009.

~~Item~~Working 3capital, 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. ~~Quantitative~~ 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 ~~Qualitative Disclosure~~Investor ~~About~~Partners ~~Market~~on ~~Rate~~a ~~Risk~~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.

~~Market~~-~~Sensitive~~ ~~Instruments~~20 ~~and Risk Management~~-

~~The Partnership's primary market risk exposure is commodity price risk. This exposure is discussed in detail below:~~Index

~~Commodity~~PDC ~~Price~~2002-D ~~Risk~~LIMITED PARTNERSHIP

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

~~The~~Cash ~~following tables summarize the open futures and options contracts for the Partnership as of March 31, 2005 and 2004.~~Flows

~~Commodity~~Cash ~~Type~~Flows ~~Quantity~~From ~~Gas-Mmbtu~~Operating ~~Oil-Barrels Weighted Average Price Total Contract Amount Fair Market Value~~Activities

~~Total~~Net ~~Contracts~~cash asprovided ofby ~~March~~operating 31activities was $0.7 million for the nine months ended September 30, ~~2005~~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:

Natural Gas	Floors	72,640	4.19	-	1,936
Natural Gas	Ceilings	36,320	6.69	-	(39,913)
Oil	Floors	2,633	32.30	85,047	85
Oil	Ceilings	1,317	40.00	52,661	(21,848)

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-9-other, net, receipts of approximately $0.3 million, excluding natural gas and oil sales received from third parties and realized derivative gains.

~~PDC~~Cash ~~2002-D~~Flows ~~LIMITED PARTNERSHIP~~From Investing Activities

(AThe ~~West~~Partnership, ~~Virginia Limited~~from ~~Partnership)~~time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and oil or environmental protection. These amounts totaled approximately $51,000 and $44,000 for the nine months ended September 30, 2010 and 2009, respectively.

~~Notes~~Cash toFlows ~~Financial Statements~~From Financing Activities

~~(Unaudited)~~The Partnership initiated monthly cash distributions to investors in July 2003 and has distributed $20.6 million through September 30, 2010. The table below presents the cash distributions to the Managing General Partner and Investor Partners, including Managing General Partner distributions relating to limited partnership units repurchased, for the periods described.

Contracts maturing in 12 months following March 31, 2005

Three months ended September 30,	Managing General Partner Distributions	Investor Partners Distributions	Total Distributions

2010	$ (6,930)	$ 19,065	$ 12,135

2009	$ 161,648	$ 798,012	$ 959,660

Natural Gas	Floors	53,306	4.07	-	785
Nine months ended September 30,		Managing General Partner Distributions			Investor Partners Distributions	Total Distributions
Natural Gas	Ceilings	26,653	6.48	-	(36,005)
2010		$ 55,667			$ 595,930	$ 651,597
Oil	Floors	2,633	32.30	85,047	85
2009		$ 318,759			$ 1,713,114	$ 2,031,873
Oil	Ceilings	1,317	40.00	52,661	(21,848)

~~Prior~~The ~~Year~~decrease ~~Total~~in ~~Contracts~~total distributions for both the three months and the nine months ended September 30, 2010 as ofcompared ~~March~~to 31the same periods in 2009, ~~2004~~were primarily due to the significant decrease in cash flows from operating activities for these two periods.

Natural Gas	Floors	131,899	3.45	-	-
Natural Gas	Ceilings	65,949	4.59	-	(21,138)
Oil	Sale	8,645	31.63	273,455	(11,364)

Beginning in 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.

~~The~~- ~~maximum~~21 ~~term over which the Partnership is hedging exposure to the variability of cash flows for commodity price risk is 19 months.~~ -

~~Disclosure of Limitations~~Index

AsPDC ~~the~~2002-D ~~information~~LIMITED above incorporates only those exposures that exist at March 31, 2005, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.PARTNERSHIP

~~Item~~(A ~~4. Controls~~West ~~and~~Virginia ~~Procedures~~Limited Partnership)

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

~~-10-~~See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements, included in this report.

~~CONFORMED~~Recent ~~COPY~~Accounting Standards

~~PART~~See IINote -2, ~~OTHER INFORMATION~~Recent Accounting Standards to the accompanying unaudited condensed financial statements, included in this report.

~~Item 1. Legal~~Critical ~~Proceedings~~Accounting Policies and Estimates

~~None~~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.

~~Item~~There ~~6. Exhibits~~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 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.

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

Off-Balance Sheet Arrangements

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

~~Pursuant~~Item to3. ~~the~~Quantitative ~~requirements~~and ofQualitative ~~the~~Disclosures ~~Securities Exchange~~About ~~Act~~Market ~~of 1934 the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.~~Risk

	PDC 2002-D Limited Partnership (Registrant) By its Managing General Partner Petroleum Development Corporation
Date: May 13, 2005	/s/ Steven R. Williams Steven R. Williams Chairman
Date: May 13, 2005	/s/ Darwin L. Stump Darwin L. Stump Chief Financial Officer

Not applicable.

~~-11-~~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 30, 2010, PDC, as Managing General Partner of the Partnership, carried out an evaluation under the supervision and with the participation of the Managing General Partner’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’s Disclosure Committee in an effort to ensure that information required to be disclosed in the SEC reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required financial disclosure.

- 22 -

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 30, 2010.

(b) Changes in Internal Control over Financial Reporting

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.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

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

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 30, 2010.

Period	Total Number of Units Repurchased		Average Price Paid per Unit

July 1−31, 2010		0.50	$	2,200
August 1−31, 2010		-		-
September 1−30, 2010		-		-
Total third quarter Unit Repurchase Program repurchases		0.50

Item 3.

Defaults Upon Senior Securities

Not applicable.

Item 4.

[Removed and Reserved]

Item 5.

Other Information

Not applicable.

- 23 -

Index

PDC 2002-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.

Exhibits

(a)	Exhibit Index.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

3.1

Limited Partnership Agreement

10-K

000-50226

3.1

10/07/2010

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

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

31.1

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

31.2

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

32.1

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

- 24 -

Index

PDC 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 27, 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 27, 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 27, 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 27, 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