UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

OF 1934

For the quarterly period ended ~~September~~March 3031, ~~2011~~2012

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

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 333-47622-03

PDC 2002-C Limited Partnership

(Exact name of registrant as specified in its charter)



	West Virginia		35-2175775
	(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

(303) 860-5800

(Registrant's telephone number, including area code)

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

Yes R No £

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

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



	Large accelerated filer £		Accelerated filer £

	Non-accelerated filer £		Smaller reporting company R

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

As of ~~September~~March 3031, ~~2011~~2012 the Partnership had 471.91 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

PART I – FINANCIAL INFORMATION
		Page
	Special Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	2
	Condensed Statements of Operations (unaudited)	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1211
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2421
Item 4.	Controls and Procedures	2421
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	2522
Item 1A.	Risk Factors	2522
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	2522
Item 3.	Defaults Upon Senior Securities	2522
Item 4.	~~[Removed~~Mine ~~and~~Safety ~~Reserved]~~Disclosures	2522
Item 5.	Other Information	2522
Item 6.	Exhibits	2623
	SIGNATURES	2724

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2002-C Limited Partnership's ~~(“Partnership” or the “Registrant”)~~ business, financial condition and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements include: estimated natural gas, natural gas ~~liquid(s)~~liquids ~~or “NGL~~(s)“NGLs”) and crude oil production and reserves; ~~drilling~~ additional development plans; future cash flows and anticipated liquidity; anticipated capital expenditures; the adequacy of the Managing General Partner's casualty insurance coverage; the effectiveness of the Managing General Partner's derivative policies in achieving the Partnership's risk management objectives; and the Managing General Partner's strategies, plans and objectives.

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

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


•	changes in production volumes and worldwide demand;


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


•	the impact of governmental fiscal terms and/or regulations, including changes in environmental laws, the regulation and enforcement related to those laws and the costs to comply with those laws, as well as other regulations;


•	changes in estimates of proved reserves;


•	inaccuracy of reserve estimates and expected production rates;


•	the potential for production decline rates from the Partnership's wells to be greater than expected;


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

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


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

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

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


•	the Partnership's future cash flow, liquidity and financial position;


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

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


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


•	the timing and receipt of necessary regulatory permits;


•	competition in the oil and gas industry;


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

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


•	the cost of pending or future litigation;


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


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

Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership's annual report on Form 10-K for the year ended December 31, ~~2010~~2011 filed with the United States Securities and Exchange Commission (“SEC”) on ~~June~~March 3020, ~~2011~~2012 (“~~2010~~2011 Form 10-K”) and the Partnership's other filings with the SEC for further information on risks and uncertainties that could affect the Partnership's business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

-1-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

PDC 2002-C Limited Partnership

Condensed Balance Sheets

(unaudited)

	September 30, 2011			December 31, 2010*
	March 31, 2012			December 31, 2011*
Assets
Current assets:
Cash and cash equivalents	$	~~117~~7,~~340~~331		$	~~117~~7,~~209~~363
Accounts receivable	5323,~~381~~735			5857,~~875~~318
Crude oil inventory	157,~~568~~800			919,~~630~~370
Due from Managing General Partner-derivatives	~~141~~207,~~748~~208			~~105~~181,~~943~~946
Total current assets	~~328~~246,~~037~~074			~~291~~265,~~657~~997
Natural gas and crude oil properties, successful efforts method, at cost	86,~~003~~969,~~515~~399			76,~~970~~969,~~695~~336
Less: Accumulated depreciation, depletion and amortization	(54,~~560~~929,~~916~~386		)	(54,~~378~~882,~~194~~949		)
Natural gas and crude oil properties, net	2,~~442~~040,~~599~~013			2,~~592~~086,~~501~~387
Due from Managing General Partner-derivatives	~~134~~123,~~102~~029			~~172~~144,~~055~~180
Other assets	4043,~~422~~771			3442,~~873~~160
Total non current assets	2,~~617~~206,~~123~~813			2,~~799~~272,~~429~~727
Total Assets	$	2,~~945~~452,~~160~~887		$	32,~~091~~538,~~086~~724
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	95,~~055~~035		$	7104,~~829~~137
Due to Managing General Partner-derivatives	8276,~~780~~959			~~100~~79,~~824~~281
Due to Managing General Partner-other, net	~~264~~35,~~845~~753			~~182~~90,~~335~~506
Total current liabilities	~~442~~207,~~680~~747			~~290~~273,~~988~~924
Due to Managing General Partner-derivatives	8753,~~889~~383			~~129~~71,~~997~~474
Asset retirement obligations	~~161~~224,~~228~~952			~~154~~221,~~237~~153
Total liabilities	~~691~~486,~~797~~082			~~575~~566,~~222~~551
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	~~453~~397,~~860~~928			~~504~~398,~~612~~287
Limited Partners - 471.91 units issued and outstanding	1,~~799~~568,~~503~~877			21,~~011~~573,~~252~~886
Total Partners' equity	21,~~253~~966,~~363~~805			21,~~515~~972,~~864~~173
Total Liabilities and Partners' Equity	$	2,~~945~~452,~~160~~887		$	32,~~091~~538,~~086~~724

*Derived from audited ~~2010~~2011 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2-

PDC 2002-C Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
	2011			2010			2011			2010
	2012			2011
Revenues:
Natural gas, NGLs and crude oil sales	$	~~147~~104,~~271~~950		$	~~128~~135,~~960~~788		$	~~415,979~~		$	~~474,400~~
Commodity price risk management gain, net	54,656			99,697			66,026			300,485
Commodity price risk management gain (loss), net	55,545			(21,856		)
Total revenues	~~201~~160,~~927~~495			~~228~~113,~~657~~932			~~482,005~~			~~774,885~~
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	8279,~~696~~432			6337,~~039~~913			~~262,132~~			~~248,996~~
Direct costs - general and administrative	9729,~~032~~060			74,~~915~~530			~~260,323~~			~~14,437~~
Depreciation, depletion and amortization	6446,~~770~~437			8960,~~751~~545			~~182,722~~			~~293,789~~
Accretion of asset retirement obligations	23,~~365~~799			2,~~228~~296			~~6,991~~			~~6,584~~
Total operating costs and expenses	~~246~~158,~~863~~728			~~162~~105,~~933~~284			~~712,168~~			~~563,806~~
Income (loss) from operations	(44,936		)	65,724			(230,163		)	211,079
Income from operations	1,767			8,648
Interest income	~~185~~4			4243			~~272~~			~~126~~
Net income (loss)	$	(44,751	)	$	65,766		$	(229,891	)	$	211,205
Net income	$	1,771		$	8,691
Net income (loss) allocated to partners	$	(44,751	)	$	65,766		$	(229,891	)	$	211,205
Net income allocated to partners	$	1,771		$	8,691
Less: Managing General Partner interest in net income (loss)	(8,950		)	13,153			(45,978		)	42,241
Less: Managing General Partner interest in net income	354			1,738
Net income (loss) allocated to Investor Partners	$	(35,801	)	$	52,613		$	(183,913	)	$	168,964
Net income allocated to Investor Partners	$	1,417		$	6,953
Net income (loss) per Investor Partner unit	$	(76	)	$	111		$	(390	)	$	358
Net income per Investor Partner unit	$	3		$	15
Investor Partner units outstanding	471.91			471.91			~~471.91~~			~~471.91~~

See accompanying notes to unaudited condensed financial statements.

-3-

PDC 2002-C Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	Three months ended March 31,
	2011			2010
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	(229,891	)	$	211,205
Net income	$	1,771		$	8,691
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Adjustments to net income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization	~~182~~46,~~722~~437			~~293~~60,~~789~~545
Accretion of asset retirement obligations	63,~~991~~799			62,~~584~~296
Unrealized gain on derivative transactions	(58,004		)	(210,972		)
Unrealized loss (gain) on derivative transactions	(24,524		)	25,083
Changes in operating assets and liabilities:
Changes in assets and liabilities:
Decrease in accounts receivable	533,~~494~~583			347,~~668~~045
Decrease (increase) in crude oil inventory	(511,~~938~~570		)	2(5,~~243~~910		)
Increase in other assets	(51,~~549~~611		)	(51,~~462~~865		)
Increase (decrease) in accounts payable and accrued expenses	87,226			(287		)
Decrease in accounts payable and accrued expenses	(9,102		)	(2,340		)
Increase in Due to Managing General Partner - other, net	82,510			69,809
Decrease in Due to Managing General Partner - other, net	(54,816		)	(69,009		)
Net cash provided by operating activities	657,~~561~~107			~~401~~24,~~577~~536
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	~~(32,820~~—		)	(2411,~~201~~816		)
Net cash used in investing activities	~~(32,820~~—		)	(2411,~~201~~816		)
Cash flows from financing activities:
Distributions to Partners	(327,~~610~~139		)	(~~372~~12,~~992~~677		)
Net cash used in financing activities	(327,~~610~~139		)	(~~372~~12,~~992~~677		)
Net increase in cash and cash equivalents	131			4,384
Net increase (decrease) in cash and cash equivalents	(32		)	43
Cash and cash equivalents, beginning of period	~~117~~7,~~209~~363			~~112~~117,~~781~~209
Cash and cash equivalents, end of period	~~117~~7,~~340~~331			117,~~165~~252

See accompanying notes to unaudited condensed financial statements.

-4-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2011~~2012

(unaudited)

Note 1−General and Basis of Presentation

PDC 2002-C Limited Partnership (the “Partnership” or the “Registrant”) was organized in 2002 as a limited partnership, in accordance with the laws of the State of West Virginia, for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations ~~of the Partnership~~ commenced upon closing of an offering for the sale of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of ~~September~~March 3031, ~~2011~~2012, there were ~~473~~471 limited partners in the Partnership (“Investor Partners”). PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the ~~limited partners (“~~Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through ~~September~~March 3031, ~~2011~~2012, the Managing General Partner has repurchased 2029.65 units of Partnership interests from the Investor Partners at an average price of $53,~~366~~818 per unit. As of ~~September~~March 3031, ~~2011~~2012, the Managing General Partner owns ~~23.5~~25% of the Partnership.

Beginning in June 2011, when the Investor Partner's average annual rate of return fell below 12.8%, the Partnership modified 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. Distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $~~1,748~~715 for the ~~nine~~three months ended ~~September~~March 3031, ~~2011~~2012 as a result of the Preferred Cash Distribution made under the terms in Section 4.02, which expires in April 2013. There were no Preferred Cash Distributions prior to June 2011. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions to the Partnership's financial statements that accompany the ~~2010~~2011 Form 10-K.

~~The~~In ~~Partnership~~the ~~expects~~Managing ~~continuing~~General ~~operations~~Partner's opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of ~~its~~only ~~natural~~normal ~~gas~~recurring ~~and~~adjustments) ~~crude~~necessary ~~oil~~for ~~properties~~a ~~until~~fair ~~such~~statement ~~time~~of the Partnership's ~~wells~~financial ~~are~~statements ~~depleted~~for orinterim ~~become~~periods ~~uneconomical~~in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to ~~produce~~Form 10-Q and Article 8 of Regulation S-X of the Securities and Exchange Commission (“SEC”). Accordingly, atpursuant ~~which~~to ~~time~~such ~~they~~rules ~~may~~and beregulations, ~~sold~~certain notes and other financial information included in the audited financial statements have been condensed or ~~plugged,~~omitted. The ~~reclaimed~~information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership's audited financial statements and ~~abandoned~~notes thereto included in the Partnership's 2011 Form 10-K. The Partnership's ~~maximum~~accounting ~~term~~policies ofare ~~existence~~described ~~extends~~in ~~through~~the ~~December 31~~Notes to Financial Statements in the Partnership's 2011 Form 10-K and updated, ~~2050~~as necessary, ~~unless~~in ~~dissolved~~this byForm ~~certain~~10-Q. The ~~conditions~~results ~~stipulated~~of ~~within~~operations for the ~~Agreement~~three months ended March 31, ~~which~~2012, ~~are~~and ~~unlikely~~the tocash ~~occur~~flows atfor ~~this~~the ~~time~~same period, oris bynot ~~written~~necessarily ~~consent~~indicative of the ~~Investor~~results ~~Partners~~to ~~owning~~be aexpected ~~majority~~for ofthe ~~outstanding~~full ~~units~~year ator ~~that~~any ~~time~~other future period.

In the Managing General Partner's opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership's financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities and Exchange Commission (“SEC”). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership's audited financial statements and notes thereto included in the Partnership's 2010 Form 10-K. The Partnership's accounting policies are described in the Notes to Financial Statements in the Partnership's 2010 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three and nine months ended September 30, 2011, and the cash flows for the same periods, are not necessarily indicative of the results to be expected for the full year or any other future period.

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

-5-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2011~~2012

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for the Partnership's financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership's financial statements.

Recently Issued Accounting Standards

Fair Value Measurement

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

Note 3−Transactions with Managing General Partner ~~and Affiliates~~

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner 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 open derivative instruments is recorded on the condensed balance sheets under the captions “Due from Managing General Partner-derivatives,” in the case of net unrealized gains and “Due to Managing General Partner-derivatives,” in the case of net unrealized losses.

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

	September 30, 2011			December 31, 2010
	March 31, 2012			December 31, 2011
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	3615,~~347~~158		$	5440,~~130~~289
Commodity price risk management, realized gain	422,~~514~~100			156,~~686~~118
Other (1)	(~~305~~73,~~706~~011		)	(~~252~~136,~~151~~913		)
Total Due to Managing General Partner-other, net	$	(~~264~~35,~~845~~753	)	$	(~~182~~90,~~335~~506	)


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

-6-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2011~~2012

(unaudited)

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~~March 3031, ~~2011~~2012 and ~~2010~~2011. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.

Three months ended September 30,

Nine months ended September 30,

Three months ended March 31,

2011

2010

2011

2010

2012

2011

Well operations and maintenance

70,~~348~~479

5025,~~714~~970

~~226,290~~

~~201,898~~

Gathering, compression and processing fees

43,~~527~~750

54,~~797~~835

~~14,124~~

~~17,736~~

Direct costs - general and administrative

9729,~~032~~060

74,~~915~~530

~~260,323~~

~~14,437~~

Cash distributions (1) (2)

1,~~207~~102

162,~~900~~941

~~5,918~~

~~82,876~~

(1) Cash distributions include $~~293~~389 and $~~1,144~~406 during the three ~~and nine~~ months ended ~~September~~March 3031, ~~2011,~~2012 ~~respectively,~~ and $12011,~~718~~ ~~and $8,278 during the three and nine months ended September 30, 2010,~~ respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

(2) Cash distributions to the Managing General Partner were reduced by $~~660~~715 ~~and $1,748~~ during the three ~~and nine~~ months ended ~~September~~March 3031, ~~2011~~2012, ~~respectively,~~ due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. There were no Preferred Cash Distributions prior to June 2011. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

Note 4−Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. The Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires the Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

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

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

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes the Partnership's natural gas collars.

Derivative Financial Instruments. The Managing General Partner measures the fair value of the Partnership's derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

-7-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2011~~2012

(unaudited)

~~Note~~The Managing General Partner validates its fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4~~−Fair~~) ~~Value~~monitoring ~~Measurements~~changes in valuation methods and ~~Disclosures~~assumptions. While the Managing General Partner uses common industry practices to develop its 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 its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

~~Derivative~~The ~~Financial~~Managing ~~Instruments~~General Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also major lenders in the Managing General Partner's corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments is insignificant.

~~Determination~~The offollowing ~~fair~~table ~~value.~~presents, ~~Fair~~for ~~value~~each ~~accounting standards have established a fair value~~ hierarchy ~~that~~level, ~~prioritizes~~ the ~~inputs~~Partnership's ~~used~~derivative inassets ~~applying~~and ~~a valuation methodology. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date~~liabilities, ~~giving~~including ~~the~~both ~~highest~~current ~~priority to quoted prices in active markets (Level 1)~~ and ~~the~~non-current ~~lowest priority to unobservable data (Level 3). In some cases~~portions, ~~the~~measured ~~inputs~~at ~~used to measure~~ fair value ~~might~~on ~~fall~~a inrecurring ~~different levels of the fair value hierarchy~~basis. ~~Financial~~These ~~assets~~derivative ~~and~~instruments ~~liabilities~~were ~~are~~comprised ~~classified in their entirety based on the lowest level~~ of ~~input~~commodity ~~that is significant to the fair value measurement. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment~~collars, ~~considering~~commodity ~~factors~~fixed-price ~~specific~~swaps ~~to the asset or liability,~~ and ~~their~~basis ~~placement within the fair value hierarchy levels~~swaps. ~~The three levels of inputs that may be used to measure fair value are defined as:~~

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



	March 31, 2012						December 31, 2011
	Level 2		Level 3		Total		Level 2		Level 3		Total

Assets:

Current
Commodity based derivatives	$	202,212	$	4,996	$	207,208	$	176,059	$	5,887	$	181,946

Non-Current
Commodity based derivatives	123,029		—		123,029		144,180		—		144,180

Total assets	325,241		4,996		330,237		320,239		5,887		326,126

Liabilities:

Current
Basis protection derivative contracts	76,959		—		76,959		79,281		—		79,281

Non-Current
Basis protection derivative contracts	53,383		—		53,383		71,474		—		71,474

Total liabilities	130,342		—		130,342		150,755		—		150,755

Net asset (1)	$	194,899	$	4,996	$	199,895	$	169,484	$	5,887	$	175,371

~~Level 2 - Inputs other than quoted prices included within Level~~ (1)As ~~that~~of ~~are either directly or indirectly observable for the asset or liability~~March 31, ~~including~~2012 ~~(i)~~and ~~quoted prices for similar assets or liabilities in active markets~~December 31, ~~(ii) quoted prices for identical or similar assets or liabilities in inactive markets~~2011, ~~(iii)~~none ~~inputs~~of ~~other than quoted prices that are observable for~~ the ~~asset~~Partnership's orderivative ~~liability~~instruments ~~and~~were ~~(iv)~~designated ~~inputs~~as ~~that are derived from observable market data by correlation or other means~~hedges.

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

Derivative Financial Instruments. The Managing General Partner measures the fair value of its derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets, both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The counterparties to the Partnership's derivative instruments are primarily financial institutions. The Managing General Partner validates the fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

-8-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2011~~2012

(unaudited)

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

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



	Three months ended
	March 31, 2012			March 31, 2011
Fair value, net asset, beginning of period	$	5,887		$	10,169
Changes in fair value included in statement of operations line item:
Commodity price risk management gain (loss), net	1,359			1,316
Settlements	(2,250		)	(8,992		)
Fair value, net asset, end of period	$	4,996		$	2,493

Change in unrealized gain (loss) relating to assets (liabilities) still held as of
March 31, 2012 and 2011, respectively, included in statement of operations line item:
Commodity price risk management gain (loss), net	$	1,160		$	—

	September 30, 2011						December 31, 2010 (a)
	Level 2 (b)		Level 3 (c)		Total		Level 2 (b)		Level 3 (c)		Total
Assets:
Commodity based derivatives	$	272,056	$	3,794	$	275,850	$	267,829	$	10,169	$	277,998
Total assets	272,056		3,794		275,850		267,829		10,169		277,998
Liabilities:
Commodity based derivatives	3,440		—		3,440		35,748		—		35,748
Basis protection derivative contracts	167,229		—		167,229		195,073		—		195,073
Total liabilities	170,669		—		170,669		230,821		—		230,821
Net asset	$	101,387	$	3,794	$	105,181	$	37,008	$	10,169	$	47,177

The significant unobservable input used in the fair value measurement of the Partnership's derivative contracts is the implied volatility curve, and is provided by a third party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of the Partnership's Level 3 derivative contracts.

(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by approximately $268,000) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by approximately $231,000). The amounts presented reflect these reclassifications and conform to current period presentation.

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

	Nine months ended
	September 30, 2011			September 30, 2010 (1)
Fair value, net asset, beginning of period	$	10,169		$	22,025
Changes in fair value included in statement of operations line item:
Commodity price risk management gain, net	2,617			18,816
Settlements	(8,992		)	(22,204		)
Fair value, net asset, end of period	$	3,794		$	18,637
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
September 30, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management gain, net	$	1,301		$	16,637

(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by approximately $194,000). The amounts presented reflect these reclassifications and conform to current period presentation.

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

Non-Derivative Financial Assets and Liabilities

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

Note 5−Derivative Financial Instruments

As of March 31, 2012, the Partnership had derivative instruments in place for a portion of its anticipated natural gas production through 2013 for a total of 83,809 MMbtu.

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



	Three months ended March 31,
	2012							2011
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains	$	27,858		$	3,163	$	31,021	$	2,316		$	911		$	3,227
Unrealized gains (losses)	(27,858		)	52,382		24,524		(2,316		)	(22,767		)	(25,083		)
Total commodity price risk management gain (loss), net	$	—		$	55,545	$	55,545	$	—		$	(21,856	)	$	(21,856	)

-9-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2011~~2012

(unaudited)

~~Note 5−~~Derivative ~~Financial~~Counterparties. The ~~Instruments~~Managing General Partner makes use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner's credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership's derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.

As of September 30, 2011, the Partnership had derivative instruments in place for a portion of its anticipated natural gas production through 2013 for a total of 109,810 MMbtu and its anticipated crude oil production through December of 2011 for a total of 420 Bbl.

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

			Fair Value
			September 30,		December 31,
Derivative instruments not designated as hedge(1):		Balance Sheet Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	141,748	$	105,943
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives	134,102		172,055
Total Derivative Assets			$	275,850	$	277,998
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	3,440	$	35,748
	Basis protection contracts	Due to Managing General Partner-derivatives	79,340		65,076
	Non Current
	Basis protection contracts	Due to Managing General Partner-derivatives	87,889		129,997
Total Derivative Liabilities			$	170,669	$	230,821

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

-10-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

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

	Three months ended September 30,
	2011							2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	961		$	3,927	$	4,888	$	9,934		$	6,794	$	16,728
Unrealized gains (losses)	(961		)	50,729		49,768		(9,934		)	92,903		82,969
Total commodity price risk management gain, net	$	—		$	54,656	$	54,656	$	—		$	99,697	$	99,697
	Nine months ended September 30,
	2011							2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	7,857		$	165	$	8,022	$	25,596		$	63,917	$	89,513
Unrealized gains (losses)	(7,857		)	65,861		58,004		(25,596		)	236,568		210,972
Total commodity price risk management gain, net	$	—		$	66,026	$	66,026	$	—		$	300,485	$	300,485

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

Note 6−Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the ~~natural~~oil ~~gas~~ and ~~crude~~gas ~~oil~~ industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to ~~avoid~~prevent 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 remediation efforts are probable and the costs can be reasonably estimated. During the three months ended ~~September~~March 3031, ~~2011~~2012, there were no new ~~material~~ environmental remediation projects identified by the Managing General Partner for the Partnership. As of ~~September~~March 3031, ~~2011~~2012, the Partnership has accrued environmental remediation liabilities for ~~one~~two ~~Partnership well in the amount~~ of ~~approximately $90,000. At December 31, 2010,~~ the Partnership's ~~had~~wells ~~accrued environmental remediation liabilities for one Partnership well~~ in the amount of approximately $293,000~~. The~~, ~~accruals~~which ~~for~~is ~~environmental remediation liabilities are~~ included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheet. At December 31, 2011, the Partnership had accrued environmental remediation liabilities for the same projects for approximately $99,000. The Managing General Partner is not currently aware of any environmental claims existing as of ~~September~~March 3031, ~~2011~~2012, which have not been provided for or would otherwise have a material impact on the Partnership's condensed financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership's properties.

-1110-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

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

Partnership Overview

PDC 2002-C Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in November 2002 and operates 14 gross (12.7 net) productive wells located in the Rocky Mountain Region in the state of Colorado. The Managing General Partner markets the Partnership's natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities orand ~~oil~~petroleum ~~companies~~refiners or marketers, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge a separate fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Due to the Investor Partner's average annual rate of return being less than 12.8% in June 2011, the Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution. See Footnote 1 - General and Basis of Presentation and Item 2 - Financial Condition, Liquidity and Capital Resources - Cash Flows for additional information and the effect of this modification on distributions.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, ~~which~~beginning ~~began~~ in the fall of 2010 and ~~extends~~extending through ~~2012~~2013, the acquisition of the limited partnership units, ~~(the “Acquisition Plan”) held by Investor Partners of the particular partnership~~ other than those held by PDC or its affiliates, held by limited partners (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership (the “Acquisition Plan”). For additional information regarding ~~PDC's~~the ~~intention~~Acquisition ~~to pursue acquisitions of PDC sponsored partnerships~~Plan, refer to prior disclosure included in PDC's filings made with the SEC and presentations on PDC's website. 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 will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of such limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and each non-affiliated investor partner will receive the right to receive a cash payment for their limited partnership units in that partnership and will no longer participate in that partnership's future earnings or ~~any~~the ~~further~~Partnership's economic benefit.

InDuring ~~June~~2010 and 2011, PDC ~~acquired~~purchased ~~three~~twelve ~~affiliated~~ partnerships: for an aggregate amount of $107.7 million. The feasibility and timing of any future cash purchase offer by PDC ~~2005-A~~to ~~Limited~~any additional partnership, including this Partnership, ~~PDC~~depends ~~2005~~on that partnership's suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-Blife ~~Limited~~stage ~~Partnership~~characteristics of the partnership's well inventory; favorability of economics for additional development in the Wattenberg Field, including commodity prices; and ~~Rockies~~SEC ~~Region~~reporting ~~Private~~compliance ~~Limited~~status ~~Partnership~~and timing and ability to achieve all necessary SEC approvals required to commence a merger and repurchase offer. On December 21, 2011, PDC ~~purchased~~and ~~these~~its ~~partnerships~~wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to eleven partnership repurchases completed by mergers in 2010 and 2011. The action was filed in United States ("U.S.") District Court for the ~~aggregate~~Central ~~amount~~District of ~~$43~~California, and is titled Schulein v.0 ~~million~~Petroleum Development Corp. The complaint alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty claim. On February 10, 2012, PDC filed a motion to dismiss or in the alternative to stay. The motion was argued on April 2, 2012. The Court has not filed a ruling at this time. The case is set for a scheduling conference on June 11, 2012. The Managing General Partner believes the suit is without merit and intends to defend it vigorously. There is no assurance that any potential proposed repurchase offer to any other of PDC's various public limited partnerships, including this Partnership, will occur.

~~In November 2011, PDC acquired five additional affiliated partnerships: PDC 2003~~-~~A Limited Partnership, PDC 2003~~11-~~B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and the PDC 2002-D Limited Partnership, for the aggregate amount of $29.5 million.~~

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

-12-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

~~Well~~Additional ~~Refracturing~~Development Plan

The Managing General Partner has prepared a plan for the Partnership's Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “~~Well~~Additional ~~Refracturing~~Development Plan”). The ~~Well~~Additional ~~Refracturing~~Development Plan consists of the Partnership's refracturing of wells currently producing in the Codell formation and/or recompletion in the Niobrara or Codell formation which is currently not producing. Under the ~~Well~~Additional ~~Refracturing~~Development Plan, the Partnership plans to initiate ~~refracturing~~additional development activities during 2013. Refracturing 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. Historically, refracturing and recompletion activities have resulted in an increase in both liquids and natural gas production.

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

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

Current estimated costs for these well refracturings or recompletions are between $~~175~~180,000 and $~~240~~260,000 per activity. As of ~~September~~March 3031, ~~2011~~2012, this Partnership had scheduled to complete ~~seven~~17 ~~refracturing~~additional development opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $13.2 million and $13.76 million if all of the activities are performed. The Managing General Partner will continually evaluate the timing of commencing these ~~refracturing~~additional development activities based on engineering data and a favorable commodity price environment in order to maximize the expected financial benefit of the additional well development. As of ~~October~~March 31, ~~2011~~2012, no funds have been withheld from the Partnership's cash distributions pursuant to the ~~Well~~Additional ~~Refracturing~~Development Plan.

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

Implementation of the ~~Well~~Additional ~~Refracturing~~Development Plan has and will continue to reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership's funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated investor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the ~~Well~~Additional ~~Refracturing~~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 ~~Well~~Additional ~~Refracturing~~Development Plan.

-1312-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Current Low Natural Gas Price Environment

The natural gas market continues to be characterized by depressed prices. While the Partnership has derivative instruments in place for a majority of its expected natural gas production, sustained low natural gas prices would result in higher realized derivative gains upon settlement but also could have a material adverse effect as a result of lower natural gas sales, a reduction in the estimated quantity of proved reserves and the estimated future net cash flows expected to be generated from these reserves.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 1223%, or approximately $5831,000, for the first ~~nine~~three months of ~~2011~~2012 compared to the first ~~nine~~three months of ~~2010~~2011, while sales volumes declined 1911% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $65.1317 for the current year period compared to $5.6698 for the same period a year ago. Realized derivative gains from natural gas ~~and crude oil~~ sales contributed an additional $01.1253 per Mcfe, or approximately $831,000, to the total revenues for the first ~~nine~~three months of ~~2011~~2012 ~~total revenues~~ compared to an additional $10.0714, or approximately $903,000, tofrom natural gas and crude oil sales for the first ~~nine~~three months of ~~2010~~2011. Comparatively, the total ~~realized price~~ per Mcfe price realized, consisting of the average sales price and realized derivative gains, ~~decreased~~increased to $6.2570 for the current year ~~nine~~three months from $6.7312 for the same prior year period.

Natural Gas, NGLs and Crude Oil Production Costs increased by approximately $42,000 during the 2012 three month period due primarily to increased workovers and tubing repair activities. Direct costs − general and administrative increased by approximately $~~246~~24,000 during the ~~2011~~2012 ~~nine~~three month period due to ~~increased~~the timing of fees for professional services.

-1413-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

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

	Three months ended September 30,								Nine months ended September 30,
	Three months ended March 31,
	2011			2010			Change		2011			2010		Change
	2012			2011			Change
Number of gross producing wells (end of period)	1413			14			—(1	)	14			14		—
Production(1)
Natural gas (Mcf)	14,~~979~~072			1916,~~538~~075			(2312	)%	~~46,564~~			~~59,066~~		~~(21~~	)%
NGLs (Bbl)	~~463~~385			~~418~~393			11(2	)%	~~1,229~~			~~1,352~~		(9	)%
Crude oil (Bbl)	~~928~~651			~~710~~713			31(9	)%	~~2,314~~			~~2,767~~		~~(16~~	)%
Natural gas equivalents (Mcfe)(2)	2320,~~325~~288			2622,~~306~~711			(11	)%	~~67,822~~			~~83,780~~		~~(19~~	)%
Average Mcfe per day	~~254~~223			~~286~~252			(1112	)%	~~248~~			~~307~~		~~(19~~	)%
Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	5028,~~442~~282		$	6453,~~185~~437		(2147	)%	$	~~152,988~~		$	~~220,224~~	~~(31~~	)%
NGLs	2015,~~813~~525			1420,~~954~~370			39(24	)%	~~60,847~~			~~55,695~~		9	%
Crude oil	7661,~~016~~143			4961,~~821~~981			53(1	)%	~~202,144~~			~~198,481~~		2	%
Total natural gas, NGLs and crude oil sales	$	~~147~~104,~~271~~950		$	~~128~~135,~~960~~788		14(23	)%	$	~~415,979~~		$	~~474,400~~	~~(12~~	)%
Realized Gain (Loss) on Derivatives, net
Natural gas	$	1231,~~691~~021		$	312,~~494~~328		*152	%	$	~~37,631~~		$	~~53,639~~	~~(30~~	)%
Crude oil	~~(7,803~~—		)	13(9,~~234~~101		)	(~~159~~100	)%	~~(29,609~~		)	~~35,874~~		~~(183~~	)%
Total realized gain on derivatives, net	$	431,~~888~~021		$	163,~~728~~227		~~(71~~*	)%	$	~~8,022~~		$	~~89,513~~	~~(91~~	)%
Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	32.3701		$	3.2932		3(40	)%	$	~~3.29~~		$	~~3.73~~	~~(12~~	)%
NGLs (per Bbl)	4440.9532			3551.7883			26(22	)%	~~49.51~~			~~41.19~~		20	%
Crude oil (per Bbl)	8193.9192			7086.1793			178	%	~~87.36~~			~~71.73~~		22	%
Natural gas equivalents (per Mcfe)	65.3117			45.9098			29(13	)%	~~6.13~~			~~5.66~~		8	%
Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	4.21		$	34.4609		223	%	$	~~4.09~~		$	~~4.64~~	~~(12~~	)%
NGLs (per Bbl)	4440.9532			3551.7883			26(22	)%	~~49.51~~			~~41.19~~		20	%
Crude oil (per Bbl)	7393.5192			8874.8117			~~(17~~27	)%	~~74.56~~			~~84.70~~		~~(12~~	)%
Natural gas equivalents (per Mcfe)	6.5270			56.5412			189	%	~~6.25~~			~~6.73~~		(7	)%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	3.5592		$	21.4067		30135	%	$	~~3.86~~		$	~~2.97~~	25	%
Depreciation, depletion and amortization	$	2.7829		$	32.4167		(1914	)%	$	~~2.69~~		$	~~3.51~~	~~(23~~	)%
Operating costs and expenses:
Direct costs - general and administrative	$	9729,~~032~~060		$	74,~~915~~530		*		$	~~260,323~~		$	~~14,437~~	*
Depreciation, depletion and amortization	$	6446,~~770~~437		$	8960,~~751~~545		(2823	)%	$	~~182,722~~		$	~~293,789~~	~~(38~~	)%
Cash distributions	$	7,~~869~~139		$	7512,~~912~~677		(9044	)%	$	~~32,610~~		$	~~372,992~~	~~(91~~	)%

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

Amounts may not ~~calculate~~recalculate due to rounding.

-1514-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

_______________

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

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

(3) ~~Represent~~Represents natural gas, NGLs and crude oil operating expenses which include production taxes.

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

• Bbl –- One barrel of crude oil or 42natural ~~U.S.~~gas liquids ("NGLs") or 42 gallons of liquid volume.

•Btu ~~MBbl~~- –British ~~One~~thermal ~~thousand barrels~~unit.

•MBbl ~~Mcf~~- – One thousand ~~cubic~~barrels ~~feet~~of crude oil or NGLs.

•Mcf ~~MMcf~~- – One ~~million~~thousand cubic feet of natural gas volume.

• Mcfe –- One thousand cubic feet of natural gas ~~equivalents~~equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL).

•MMBtu ~~MMcfe~~- – One million ~~cubic~~British ~~feet~~thermal ~~of natural gas equivalents~~units.

•MMcf ~~MMbtu~~- – One million ~~British~~cubic ~~Thermal~~feet ~~Units~~of natural gas volume.

MMcfe - One million cubic feet of natural gas equivalent.

Natural Gas, NGLs and Crude Oil Sales

~~Nine~~Natural ~~months~~Gas, ~~ended~~NGLs ~~September~~and 30Crude Oil Pricing. The Partnership's results of operations depend upon many factors, ~~2011~~particularly asthe ~~compared~~price of natural gas, NGLs and crude oil and the Managing General Partner's ability to ~~nine~~market ~~months~~the ~~ended~~Partnership's ~~September~~production 30effectively. Natural gas, ~~2010~~NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on the Partnership's financial results and capital expenditures. The Partnership has experienced a decline in the price of NGLs, mainly at Conway hub in Kansas where the Partnership's Wattenberg production is priced, primarily due to increased ethane volumes and the limited market for ethane. Natural gas and NGL prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. The combination of increased drilling activity and the lack of local markets has resulted in local market oversupply situations from time to time. Like most producers, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership's control. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics.

~~For~~The price the ~~nine~~Partnership ~~months~~receives ~~ended~~for ~~September~~its ~~30,~~natural ~~2011~~gas ~~compared~~produced toin the ~~same~~Rocky ~~period~~Mountain inRegion ~~2010~~is based on a market basket of prices, which generally includes natural gas sold at, ~~NGLs~~near ~~and~~or ~~crude~~below ~~oil~~CIG ~~sales~~prices ~~volume,~~as onwell anas ~~energy~~other ~~equivalency-basis~~nearby region prices. The CIG Index, ~~decreased~~and ~~19%~~other ~~due~~indices for production delivered to ~~normal~~other ~~production~~Rocky ~~declines~~Mountain pipelines, has historically been less than the price received for ~~this~~natural ~~stage~~gas produced in the ~~wells'~~eastern ~~production~~regions, ~~life~~which ~~cycle~~is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years. The negative differential between NYMEX and CIG averaged $0.12 and $0.28 for the three months ended March 31, 2012 and 2011, respectively.

~~The~~Three ~~approximately~~months ~~$58,000,~~ended orMarch ~~12%~~31, ~~decrease~~2012 ~~in sales for the 2011 nine month period~~ as compared to ~~the~~three ~~prior~~months ~~year~~ended ~~period,~~March ~~was primarily a reflection of sales volume decreases of 19% partially offset by an 8% increase in average sales prices. The average sales price per Mcfe~~31, ~~excluding the impact of realized derivative gains, was $6.13 for the current year nine month period compared to $5.66 for the same period a year ago.~~ 2011

~~Natural~~For ~~gas~~the ~~sales~~three ~~decreased~~months byended March 31%, ~~while~~2012 ~~NGLs~~compared ~~and~~to ~~crude~~the ~~oil~~same ~~sales~~period ~~increased~~in ~~by 9% and 2%~~2011, ~~respectively. The Partnership's~~ natural gas, ~~sales~~NGLs ~~decrease~~and ~~resulted~~crude ~~from~~oil ~~lower~~sales ~~Partnership natural gas production~~ volumes, ofon ~~21%~~an ~~and~~energy ~~from~~equivalency-basis, decreased ~~average commodity price per Mcf of 12~~11%~~. The NGLs~~ ~~sales increased~~ due to ~~increased~~normal ~~average~~production ~~commodity~~declines ~~price~~for ~~per~~this ~~Bbl~~stage ~~of 20%, partially offset by a decrease of 9%~~ in ~~NGLs production volumes. The crude oil sales increase was due primarily to increased average commodity price per Bbl of 22%, partially offset by sales volume decreases of 16% during~~ the ~~current~~wells' ~~nine~~production ~~month~~life ~~period~~cycle.

~~Three~~The ~~months~~$31,000, ~~ended~~or ~~September 30~~23%, ~~2011~~decrease in sales for the 2012 three month period as compared to ~~three~~the ~~months~~prior ~~ended~~year ~~September 30~~period was a reflection of sales volume decreases of 11% and a decline in average sales prices of 13%. The average sales price per Mcfe, ~~2010~~excluding the impact of realized derivative gains, was $5.17 for the current year three month period compared to $5.98 for the same period a year ago.

~~For~~Natural ~~the~~gas, ~~three~~NGLs ~~months~~and ~~ended~~crude ~~September 30~~oil sales decreased by 47%, ~~2011~~24% ~~compared~~and to1%, ~~the~~respectively. The ~~same~~Partnership's ~~period~~natural ingas ~~2010,~~sales decrease resulted from decreased commodity prices per Mcf of 40% and lower Partnership natural gas, production volumes of 12%. The decrease in NGLs sales was due to a decrease of 2% in NGLs production volumes and a decrease in the average commodity price per Bbl of 22%. The crude oil sales decrease was due primarily to sales volume decreases of 9%, onpartially anoffset ~~energy~~by ~~equivalency-basis,~~an ~~decreased~~increase ~~11%~~in ~~due~~the toaverage ~~normal~~commodity ~~production~~price ~~declines~~per ~~for~~Bbl ~~this~~of ~~stage~~8% induring the ~~wells'~~current ~~production~~three ~~life~~month ~~cycle~~period.

The approximately $18,000, or 14%, increase in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of an increase in average sales prices of 29%, partially offset by lower sales volumes of 11%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.31 for the current year three month period compared to $4.90 for the same period a year ago. -15-

NGLs and crude oil sales increased by 39% and 53%, respectively, and were partially offset by a decrease in natural gas sales per Mcf of 21%. The increase in NGLs sales was due to increased average commodity price per Bbl of 26% accompanied by an increase of 11% in NGLs production volumes. The crude oil sales increase was due primarily to sales volume increases of 31% and a rise in average commodity price per Bbl of 17% during the current three month period. The Partnership's natural gas sales decrease resulted from lower Partnership natural gas production volumes of 23%, partially offset by increased average commodity price per Mcf of 3%.

-16-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

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

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

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

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
	2011			2010			2011			2010
	2012			2011
Commodity price risk management gain, net:
Commodity price risk management gain (loss), net:
Realized gains (losses)
Natural gas	$	1231,~~691~~021		$	312,~~494~~328		$	~~37,631~~		$	~~53,639~~
Crude oil	~~(7,803~~—		)	13(9,~~234~~101		)	~~(29,609~~		)	~~35,874~~
Total realized gains, net	431,~~888~~021			163,~~728~~227			~~8,022~~			~~89,513~~
Unrealized gains
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized	(961		)	(9,934		)	(7,857		)	(25,596		)
prior periods unrealized gains	(27,858		)	(2,316		)
Unrealized gains for the period	50,729			92,903			65,861			236,568
Unrealized gains (losses) for the period	52,382			(22,767		)
Total unrealized gains, net	49,768			82,969			58,004			210,972
Total unrealized gains (losses), net	24,524			(25,083		)
Total commodity price risk management gain, net	$	54,656		$	99,697		$	66,026		$	300,485
Total commodity price risk management gain (loss), net	$	55,545		$	(21,856	)

~~Nine~~Three months ended ~~September~~March 3031, ~~2011~~2012 as compared to ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011

Realized gains of approximately $31,000 recognized in the ~~nine~~three months ended ~~September~~March 3031, ~~2011~~2012, were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. ~~Realized~~For ~~gains~~the onthree ~~natural~~months ~~gas~~ended ~~settlements~~March ~~were~~31, ~~approximately $91~~2012,~~000~~ ~~for~~realized ~~the~~gains ~~nine~~on ~~months~~natural ~~ended~~gas, ~~September~~exclusive 30of basis swaps, ~~2011~~were approximately$54,000. These gains were offset in part by anrealized ~~approximate~~losses of approximately $5323,000 ~~loss~~ on the Partnership's ~~Colorado Interstate Gas ("CIG")~~ basis ~~protection~~swap ~~swaps~~positions as the negative basis differential between NYMEX and CIG ~~was~~weighted ~~narrower~~average ~~than the strike~~ price ofwas ~~the~~narrower ~~basis~~than ~~positions. The Partnership also realized an approximate $30,000 loss on its crude oil positions due to higher spot prices at settlement compared to~~ the ~~respective~~ strike price~~. Unrealized~~ ~~gains during the nine months ended September 30, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value~~ of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of approximately $79,000 and the shift downward in the crude oil curve resulted in an unrealized gain of approximately $6,000 during the nine months ended September 30, 2011. These unrealized gains were partially offset by unrealized losses of approximately $19,000 on the Partnership's CIG basis ~~protection~~ swaps ~~as the forward basis differential between the NYMEX and CIG had continued to narrow~~.

~~The~~Unrealized ~~realized derivative~~ gains ~~for~~of ~~the 2010 nine month period were~~ approximately $9052,000~~. These~~ ~~realized~~for ~~gains~~the ~~were~~three ~~primarily~~months aended ~~result~~March of31, ~~lower~~2012, ~~natural~~were ~~gas~~primarily ~~and~~related ~~crude oil spot prices at settlement compared~~ to the ~~respective~~downward ~~strike~~shift ~~price, offset~~ in ~~part by realized losses due to~~ the ~~basis~~natural ~~differential~~gas ~~between~~forward ~~NYMEX~~curve and ~~CIG~~its ~~being~~impact ~~narrower~~on ~~than~~ the ~~strike~~fair ~~price~~value of the ~~derivative~~Partnership's ~~position. For~~open ~~the nine month period~~positions, ~~realized~~offset ~~gains~~in ~~related~~part toby ~~natural~~the ~~gas~~narrowing ~~and~~of ~~crude oil derivatives were approximately $89,000 and $36,000, respectively, and realized losses on~~ the ~~Partnership's~~ CIG basis ~~protection~~forward ~~swaps were approximately $35,000~~curve. ~~Unrealized~~ ~~gains~~For ~~for~~ the ~~2010 nine month~~ period ~~were~~ended ~~approximately~~March ~~$237~~31,~~000~~ ~~due primarily to a downward shift in the natural gas and crude oil forward curves~~2012, ~~offset by~~ unrealized ~~losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. Unrealized~~ gains on the Partnership’'s ~~commodity~~natural gas positions ~~for the 2010 nine month period~~ were approximately $~~255~~52,000, offset inslightly ~~part~~ by unrealized losses on the Partnership's CIG basis ~~position of approximately $18,000~~swaps.

~~-17-~~Realized gains recognized in the three months ended March 31, 2011 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $23,000 for the three months ended March 31, 2011. These gains were offset in part by an approximate $11,000 loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized an approximate $9,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.

Unrealized losses during the three months ended March 31, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The significant shift upward in the crude oil curve resulted in an unrealized loss of approximately $17,000 during the three months ended March 31, 2011. Likewise, the shifts upward in the natural gas and basis curves resulted in a total unrealized loss of approximately $6,000.

-16-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

The following table presents the Partnership's derivative positions in effect as of March 31, 2012.

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



	Collars					Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price				Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price		Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price			Fair Value at March 31, 2012⁽²⁾
Commodity/ Index	Quantity (Gas-MMBtu⁽¹⁾)	Floors		Ceilings		Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price		Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price			Fair Value at March 31, 2012⁽²⁾

Natural Gas
NYMEX
04/01 - 06/30/2012	378	$	6.00	$	8.27	12,229	$	6.98	12,607	$	(1.88	)	$	39,970
07/01 - 09/30/2012	512	6.00		8.27		11,990	6.98		12,502	(1.88		)	35,538
10/01 - 12/31/2012	562	6.00		8.27		11,672	6.98		12,234	(1.88		)	29,600
01/01 - 03/31/2013	—	—		—		11,752	7.12		11,752	(1.88		)	25,141
04/01 - 06/30/2013	—	—		—		11,706	7.12		11,706	(1.88		)	25,355
07/01 - 09/30/2013	—	—		—		11,620	7.12		11,620	(1.88		)	23,719
10/01 - 12/31/2013	—	—		—		11,388	7.12		11,388	(1.88		)	20,572
Total Natural Gas	1,452					82,357			83,809				199,895

Realized gains recognized in the three months ended September 30, 2011 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were approximately $34,000 for the three months ended September 30, 2011. These gains were offset in part by an approximate $21,000 loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized an approximate $8,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the three months ended September 30, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of approximately $54,000 and the shift downward in the crude oil curve resulted in an unrealized gain of approximately $7,000 during the three months ended September 30, 2011. These unrealized gains were partially offset by unrealized losses of approximately $10,000 on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow.

The realized derivative gains for the 2010 third quarter were approximately $17,000. These realized gains were a result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the quarter, realized gains related to natural gas and crude oil derivatives were approximately $32,000 and realized losses on the Partnership's CIG basis swaps were approximately $15,000. Unrealized gains for the 2010 third quarter were approximately $93,000 due primarily to a downward shift in the natural gas forward curves. These unrealized gains were partially offset by unrealized losses due to the narrowing of the NYMEX-CIG basis differential. Unrealized gains on the Partnership’s commodity positions for the 2010 three month period were approximately $103,000 partially offset by unrealized losses on the Partnership's basis position of approximately $10,000.

	Collars					Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/Index	Quantity(Gas-MMBtu(1))	Weighted AverageContract Price				Quantity(Gas-MMBtu(1)Crude Oil-Bbls)	WeightedAverageContractPrice		Quantity(Gas-MMBtu(1))	WeightedAverageContractPrice			Fair Value atSeptember 30, 2011(2)
		Floors		Ceilings
Natural Gas
NYMEX
10/01 - 12/31/2011	—	$	—	$	—	13,199	$	6.78	13,199	$	(1.88	)	$	17,054
01/01 - 03/31/2012	697	6.00		8.27		12,105	6.98		12,802	(1.88		)	14,718
04/01 - 06/30/2012	378	6.00		8.27		12,228	6.98		12,606	(1.88		)	16,059
07/01 - 09/30/2012	512	6.00		8.27		11,989	6.98		12,501	(1.88		)	14,577
10/01 - 12/31/2012	562	6.00		8.27		11,674	6.98		12,236	(1.88		)	10,667
2013	—	—		—		46,466	7.12		46,466	(1.88		)	35,546
Total Natural Gas	2,149					107,661			109,810				108,621
Crude Oil
NYMEX
10/01 - 12/31/2011	—	—		—		420	70.75		—	—			(3,440		)
Total Crude Oil	—					420			—				(3,440		)
Total Natural Gas and Crude Oil													$	105,181

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

(2) ~~Approximately~~As 1of March 31, 2012, approximately 2% of the fair value of the Partnership's derivative assets ~~and none of the Partnership's derivative liabilities~~ were measured using significant unobservable inputs (Level 3); see Note 4, Fair Value Measurements and Disclosures, to the accompanying unaudited condensed financial statements included in this report.

-18-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Natural Gas, NGLs and Crude Oil Production Costs

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

~~Nine~~Three months ended ~~September~~March 3031, ~~2011~~2012 as compared to ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011

Production ~~costs~~and ~~per~~operating ~~Mcfe~~costs ~~increased~~for ~~to $3.86 during~~ the ~~current~~three month period ~~compared~~ended toMarch ~~$2.97~~31, ~~for~~2012 ~~the~~increased ~~prior~~by ~~year~~approximately ~~period~~$42,000 ~~due~~compared to the ~~effect~~same ofperiod ~~higher~~in ~~per~~2011. Lease ~~well~~operating ~~related~~costs ~~expenditures,~~were ~~partially~~higher ~~offset~~ by ~~lower~~approximately ~~per~~$47,000 ~~volume~~in ~~related~~the ~~natural~~current ~~gas,~~period ~~NGLs~~as workovers and ~~crude~~tubing ~~oil~~repair ~~production~~activities ~~costs. Current~~collectively ~~period~~were ~~production~~lower ~~costs~~in ~~included~~the ~~environmental~~prior ~~remediation~~period. Higher ~~costs~~lease ofoperating ~~approximately~~costs ~~$90,000~~were ~~for~~partially ~~one~~offset ~~Partnership~~by ~~well~~lower inrevenue ~~2011~~and ~~compared~~volume-based ~~to environmental remediation~~ costs ofby approximately $773,000 ~~for~~in ~~three~~2012, ofconsistent ~~the~~with ~~Partnership's~~sales ~~wells~~and inproduction ~~2010~~declines from 2011. ~~Current~~ ~~period~~Production ~~production~~and operating costs ~~additionally~~per ~~include~~Mcfe ~~approximately~~increased to $~~22,000~~3.92 induring ~~maintenance~~2012 ~~costs~~from at$1.67 ~~two~~in of2011 ~~the~~due ~~Partnership's~~to ~~Wattenberg~~lower ~~Field~~volumes ~~wells~~and increased costs.

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

Production costs per Mcfe increased to $3.55 during the current period compared to $2.40 for the prior year period due to to the effect of higher per well related expenditures, partially offset by lower per volume related natural gas, NGLs and crude oil production costs. Current period production costs include approximately $22,000 in maintenance costs at two of the Partnership's Wattenberg Field wells.

Direct Costs−General and Administrative

~~Nine~~Three months ended ~~September~~March 3031, ~~2011~~2012 as compared to ~~nine~~three months ended ~~September~~March 3031, ~~2010~~2011

Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs increased during the ~~nine~~three months ended ~~September~~March 3031, ~~2011~~2012, compared to the same period in ~~2010~~2011, by approximately $~~246~~24,000, principally due to ~~increased~~the timing of fees for professional services.

~~Three months ended September 30, 2011 as compared to three months ended September 30, 2010~~-17-

Direct costs increased during the three months ended September 30, 2011 compared to the same period in 2010, by approximately $89,000 principally due to increased fees for professional services.

Depreciation, Depletion and Amortization (DD&A)

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

DD&A expense per Mcfe decreased to $2.69 for the 2011 nine month period, compared to $3.51 during the same period in 2010. The decrease of $0.82 per Mcfe for the 2011 period compared to the 2010 period was due to the effect of the upward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves particularly in the Wattenberg Field as of December 31, 2010. The production declines, noted in previous sections, also contributed to the decreased DD&A expense of approximately $111,000 for the 2011 nine month period compared to the same period in 2010.

-19-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

~~Three months ended September 30~~Depreciation, ~~2011~~Depletion asand ~~compared~~Amortization ~~to three months ended September 30, 2010~~(DD&A)

~~DD&A~~Three ~~expense~~months ~~per~~ended ~~Mcfe~~March ~~decreased to $2.78 for the 2011 three month period~~31, ~~compared~~2012 toas ~~$3.41 during the same period in 2010. The decrease of $0.63 per Mcfe for the 2011 period~~ compared to ~~the~~three ~~2010~~months ~~period~~ended ~~was~~March ~~due to the effect of the upward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves particularly in the Wattenberg Field as of December~~ 31, ~~2010. The production declines, noted in previous sections, also contributed to the decreased DD&A expense of approximately $25,000 for the~~ 2011 ~~three month period compared to the same period in 2010.~~

The DD&A expense rate per Mcfe decreased to $2.29 for the 2012 three month period, compared to $2.67 during the same period in 2011. The decrease in the per Mcfe rates for the 2012 period compared to the 2011 period is due to the effect of the 2011 impairment of the Partnership’s Piceance Basin assets. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $14,000 for the 2012 three month period compared to the same 2011 period.

Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for the ~~nine~~three months ended ~~September~~March 3031, ~~2011~~2012 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the net realized gains from the Partnership's derivative positions. These sources of cash were primarily used to fund the Partnership's operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. ~~Additionally,~~Any the Partnership's operating cash flows were increased by approximately $44,000 due to payments made by the Managing General Partner on behalf of the Partnership which increased the balance of Due to the Managing General Partner-other, net (See Working Capital below). The future repayment of the entire balance of Due to the Managing General Partner-other, net, prior to withholding any distributions to fund the Well Refracturing Plan, was taken into consideration when assessing the Partnership's ability to complete this plan. When this balance is repaid, any future withholdings would provide the funding for planned Wattenberg Field ~~well~~ refracturing or recompletion costs to be incurred ~~beginning~~during in 2013~~. For~~ ~~additional~~and ~~information~~thereafter, ~~see Item 2, Management's Discussion~~ and ~~Analysis~~are ofexpected ~~Financial~~to ~~Condition~~decrease ~~and~~distributions ~~Results~~from ofhistorical ~~Operations, Recent Developments-Well Refracturing Plan~~levels.

Fluctuations in the Partnership's operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership's cash flow from operations becomes the net activity between the Partnership's natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership's expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of ~~September~~March 3031, ~~2011~~2012, the Partnership had natural gas ~~and crude oil~~ derivative positions in place covering 7285% of the expected natural gas production ~~and 47% of expected crude oil production~~ for the remainder of ~~2011~~2012, at an average price of $45.9007 per Mcf ~~and $70~~.~~75 per Bbl~~ However, ~~respectively. The~~the Partnership's ~~current~~has ~~derivative~~no ~~position~~NGL ~~average~~or ~~prices~~crude ~~have~~oil declined from the significantly higher average commodity contract strike price levels in effect during the first quarter of 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price marketderivatives. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership's revenues.

The Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity derivatives. Natural gas, NGLs and crude oil production from the Partnership's existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of ~~2011~~2012 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the ~~refracturing~~additional development activities which are more fully described in Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments −Additional ~~Well~~Development ~~Refracturing~~ Plan.

-2018-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Working Capital

The Partnership had a working capital ~~deficit~~ of approximately $~~115~~38,000 at ~~September~~March 3031, ~~2011~~2012 compared to a working capital deficit of approximately $18,000 at December 31, ~~2010. This~~2011, ~~deficit~~an ~~arose primarily due to the~~ increase ~~in Direct costs - general and administrative resulting from the Partnership's SEC compliance effort. These costs were in excess~~ of ~~cash~~approximately ~~provided by operating activities during that period and were paid by the Managing General Partner and are being repaid by the Partnership~~$46,000. The ~~following~~increase ~~offsetting~~was ~~changes~~ primarily ~~resulted~~due ~~in a decrease of approximately $116,000~~ to the ~~working~~following ~~capital~~changes:

• Accounts receivable decreased approximately $2359,000 between ~~September~~March 3031, ~~2011~~2012 and December 31, ~~2010~~2011.

• Realized and unrealized derivative gains receivable increased by approximately $43,000 between ~~September~~March 3031, ~~2011~~2012 and December 31, ~~2010~~2011.

• ~~Due~~Oil toinventory ~~Managing~~decreased ~~General Partner-other, net increased~~ by approximately $5411,000 between ~~September~~March 3031, ~~2011~~2012 and December 31, ~~2010~~2011.

• ~~Accounts~~Due ~~payable~~to ~~increased~~Managing General Partner-other, net, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, decreased by approximately $8764,000 between ~~September~~March 3031, ~~2011~~2012 and December 31, ~~2010~~2011.

~~Working~~• ~~capital~~Accounts ispayable ~~expected~~decreased toapproximately ~~increase~~$9,000 ~~during~~between ~~periods~~March of31, ~~Well~~2012 ~~Refracturing Plan funding~~ and ~~decrease~~December ~~during~~31, ~~periods when payments are made for refracturing~~2011.

Working capital is expected to increase during periods of Additional Development Plan funding and decrease during periods when payments are made for refracturing or recompletion activities.

Cash Flows

Cash Flows ~~From~~from Operating Activities

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

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

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which generally includes natural gas sold at, near or below CIG prices in addition to other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential of CIG relative to NYMEX averaged $0.28 and $0.30 for the three and nine months ended September 30, 2011, respectively, compared to an average of $0.51 and $0.88 for the three and nine months ended September 30, 2010, respectively.

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

~~-21-~~Net cash provided by operating activities was approximately $7,000 for the three months ended March 31, 2012, compared to approximately $24,000 for the comparable period in 2011. The decrease of approximately $17,000 in net cash provided by operating activities was due primarily to the following:


•	An increase in natural gas, NGLs and crude oil sales receipts of approximately $19,000, or 13%,


•	A decrease in commodity price risk management realized gains receipts of approximately $2,000, or 14%, and


•	An increase in production costs and direct costs - general and administrative payments of approximately $34,000.

Cash Flows from Investing Activities

The Partnership, from time-to-time, invests in equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts were not significant for the three months ended March 31, 2012 and 2011, respectively.

-19-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

~~Net~~Cash ~~cash~~Flows ~~provided~~from byFinancing operating activities was approximately $66,000 for the nine months ended September 30, 2011, compared to approximately $402,000 for the comparable period in 2010. The decrease of approximately $336,000 in net cash provided by operating activities was due primarily to the following:Activities

•The APartnership ~~decrease~~initiated inmonthly ~~natural~~cash ~~gas,~~distributions ~~NGLs~~to ~~and~~investors ~~crude~~in ~~oil~~May ~~sales~~2003 ~~receipts~~and ofhas ~~approximately~~distributed $859.6 million through March 31,~~000,~~ or2012. The 16table below presents cash distributions to the Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to PDC for the Managing General Partner's 20%, general partner interest in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.

• A decrease in commodity price risk management realized gains receipts of approximately $106,000, or 85%,and



Distributions

Three months ended March 31,	Managing General Partner		Investor Partners		Total
2012	$	713	$	6,426	$	7,139
2011	2,535		10,142		12,677

•The Andecrease ~~increase~~ in ~~production~~total ~~costs~~distributions ~~and~~for ~~direct~~2012 ~~costs~~as -compared ~~general~~to ~~and~~2011 ~~administrative~~is ~~payments~~primarily ofdue ~~approximately~~to ~~$145,000~~the decrease in cash flows from operating activities during 2012.

Beginning in June 2011, when the Investor Partner's average annual rate of return fell below 12.8%, the Partnership modified 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. Distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $715 for the three months ended March 31, 2012 as a result of the Preferred Cash ~~Flows~~Distribution ~~From~~made ~~Investing~~under ~~Activities~~the terms in Section 4.02. Because of the expected production declines related to the Partnership's mature natural gas and crude oil operations, the Managing General Partner believes performance obligation allocation rate modifications are likely to continue until April 2013, when the provision expires under the terms of the Agreement.

The Partnership, from time-to-time, invests in equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts totaled approximately $33,000 and $24,000 for the nine months ended September 30, 2011 and 2010, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2003 and has distributed $9.6 million through September 30, 2011. The table below presents cash distributions to the Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to PDC for the Managing General Partner's 20% general partner interest in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.

Distributions
Three months ended September 30,	Managing General Partner		Investor Partners		Total
2011	$	914	$	6,955	$	7,869
2010	15,182		60,730		75,912
Nine months ended September 30,	Managing General Partner		Investor Partners		Total
2011	$	4,774	$	27,836	$	32,610
2010	74,598		298,394		372,992

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

Beginning in June 2011, when the Investor Partner's average annual rate of return fell below 12.8%, the Partnership modified 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. Distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $660 for the three months ended September 30, 2011 as a result of the Preferred Cash Distribution made under the terms in Section 4.02. Because of the expected production declines related to the Partnership's mature natural gas and crude oil operations, the Managing General Partner believes performance obligation allocation rate modifications are likely to continue until April 2013, when the provision expires under the terms of the Agreement.

-22-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Off-Balance Sheet Arrangements

As of ~~September~~March 3031, ~~2011~~2012, the Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on the Partnership's financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

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

Recent Accounting Standards

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

Critical Accounting Policies and Estimates

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

There have been no significant changes to the Partnership's critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership's ~~2010~~2011 Form 10-K.

-2320-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of ~~September~~March 3031, ~~2011~~2012, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of ~~September~~March 3031, ~~2011~~2012.

(b) Changes in Internal Control over Financial Reporting

During the three months ended ~~September~~March 3031, ~~2011~~2012, PDC, the Managing General Partner, made no changes in the Partnership's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership's internal control over financial reporting.

-2421-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

Not applicable.

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

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

The following table presents information about the Managing General Partner's limited partner unit repurchases during the three months ended ~~September~~March 3031, ~~2011~~2012.

Period	Total Number of Units Repurchased	Average Price Paid Per Unit
July 1 - 31	—	$	—
January 1 - 31		$	—
August 1 - 31	—	—
February 1 - 29	2.91	229
September 1 - 30	1.00	715
March 1 - 31	—	—
Total third quarter repurchases	1.00
Total first quarter repurchases	2.91

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. ~~[Removed~~Mine ~~and~~Safety ~~Reserved]~~Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

-2522-

Index

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Item 6. Exhibits

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

Incorporated by Reference

ExhibitNumber

Exhibit Description

Form

SEC FileNumber

Exhibit

Filing Date

FiledHerewith

31.1

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

31.2

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

32.1**

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

32.1*

101.INS**

XBRL Instance Document

101.INS*

XBRL Instance Document

101.SCH**

XBRL Taxonomy Extension Schema Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL**

XBRL Taxonomy Extension Calculation Linkbase Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**

XBRL Taxonomy Extension Definition Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**

XBRL Taxonomy Extension Label Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.PRE**

XBRL Taxonomy Extension Presentation Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

**Furnished herewith.

-2623-

Index

PDC 2002-C 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-C Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By: /s/ James M. Trimble James M. ~~TrimbleChief~~TrimblePresident and Chief Executive Officerof Petroleum Development Corporation (dba PDC Energy) ~~November~~May 14, ~~2011~~2012

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

Signature	Title	Date
/s/ James M. Trimble	President and Chief Executive Officer	~~November~~May 14, ~~2011~~2012
James M. Trimble	Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant
	(Principal executive officer)
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~November~~May 14, ~~2011~~2012
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant
	(Principal financial officer)
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~November~~May 14, ~~2011~~2012
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)Managing General Partner of the Registrant
	(Principal accounting officer)
	(principal accounting officer)

-2724-

Filing Compare · PDC 2002 C LTD PARTNERSHIP