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 ~~March~~June 3130, 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~~

Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area 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 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 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 (Do not check if a smaller reporting company)

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 ~~March~~June 3130, 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

~~INDEX~~TABLE TOOF ~~REPORT ON FORM 10-Q~~CONTENTS

PART I – FINANCIAL INFORMATION
		Page
	Special Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	2
	Condensed Statements of Operations (unaudited)	32
	Condensed Statements of Cash Flows (unaudited)	42
	Notes to Unaudited Condensed Financial Statements	53
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	116
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2116
Item 4.	Controls and Procedures	2116
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	2218
Item 1A.	Risk Factors	2218
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	2218
Item 3.	Defaults Upon Senior Securities	2218
Item 4.	Mine Safety Disclosures	2218
Item 5.	Other Information	2218
Item 6.	Exhibits	2319
	SIGNATURES	2420

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This ~~periodic~~Quarterly ~~report~~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 (the "Partnership" or the "Registrant") business, financial condition and results of operations. ~~Petroleum~~ ~~Development~~PDC ~~Corporation~~Energy, Inc. (“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~~relate to, among other things: estimated natural gas, natural gas liquids (“NGLs”) and crude oil production and reserves; additional development plans; the PDC-Sponsored Drilling Program Acquisition Plan discussed in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Recent Developments"; 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 future 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, including economic conditions that might impact demand;


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

• the impact of governmental ~~fiscal~~policies ~~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;


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


•	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 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 supplies and services at reasonable prices;

• risks incidental to the 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;

• 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;


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


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


•	competition in the oil and gas industry;


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


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


•	the effect of natural gas derivative activities;


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


•	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~~Quarterly Report on Form 10-Q, the Partnership's ~~annual~~Annual ~~report~~Report on Form 10-K for the year ended December 31, 2011 filed with the United States Securities and Exchange Commission (“SEC”) on March 20, 2012 (“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 and prospects, 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)

	March 31, 2012			December 31, 2011*
	June 30, 2012			December 31, 2011*
Assets
Current assets:
Cash and cash equivalents	$	7,~~331~~298		$	7,363
Accounts receivable	2345,~~735~~120			57,318
Crude oil inventory	712,~~800~~427			19,370
Due from Managing General Partner-derivatives	~~207~~181,~~208~~123			181,946
Total current assets	~~246~~245,~~074~~968			265,997
Natural gas and crude oil properties, successful efforts method, at cost	6,969,~~399~~870			6,969,336
Less: Accumulated depreciation, depletion and amortization	(4,~~929~~979,~~386~~958		)	(4,882,949		)
Natural gas and crude oil properties, net	21,~~040~~989,~~013~~912			2,086,387
Due from Managing General Partner-derivatives	~~123~~77,~~029~~854			144,180
Other assets	4345,~~771~~509			42,160
Total non current assets	2,206,813			2,272,727
Total Assets	$	2,359,243		$	2,538,724
Total Assets	$	2,452,887		$	2,538,724
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	955,~~035~~682		$	104,137
Due to Managing General Partner-derivatives	7677,~~959~~648			79,281
Due to Managing General Partner-other, net	352,~~753~~126			90,506
Total current liabilities	~~207~~85,~~747~~456			273,924
Due to Managing General Partner-derivatives	5336,~~383~~110			71,474
Asset retirement obligations	~~224~~228,~~952~~820			221,153
Total liabilities	~~486~~350,~~082~~386			566,551
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	~~397~~407,~~928~~094			398,287
Limited Partners - 471.91 units issued and outstanding	1,~~568~~601,~~877~~763			1,573,886
Total Partners' equity	12,~~966~~008,~~805~~857			1,972,173
Total Liabilities and Partners' Equity	$	2,~~452~~359,~~887~~243		$	2,538,724

*Derived from audited 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 March 31,
	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012		2011
Revenues:
Natural gas, NGLs and crude oil sales	$	~~104~~110,~~950~~999		$	~~135~~132,~~788~~920		$	215,949	$	268,708
Commodity price risk management gain (loss), net	55(15,~~545~~303		)	~~(21~~33,~~856~~226		)	40,242		11,370
Total revenues	~~160~~95,~~495~~696			~~113~~166,~~932~~146			256,191		280,078
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	79(39,~~432~~457		)	37141,~~913~~523			39,975		179,436
Direct costs - general and administrative	2931,~~060~~038			4158,~~530~~761			60,098		163,291
Depreciation, depletion and amortization	4650,~~437~~572			6057,~~545~~407			97,009		117,952
Accretion of asset retirement obligations	3,~~799~~868			2,~~296~~330			7,667		4,626
Total operating costs and expenses	~~158~~46,~~728~~021			~~105~~360,~~284~~021			204,749		465,305
Income from operations	1,767			8,648
Income (loss) from operations	49,675			(193,875		)	51,442		(185,227		)
Interest income	43			4344			7		87
Net income	$	1,771		$	8,691
Net income (loss)	$	49,678		$	(193,831	)	$	51,449	$	(185,140	)
Net income allocated to partners	$	1,771		$	8,691
Net income (loss) allocated to partners	$	49,678		$	(193,831	)	$	51,449	$	(185,140	)
Less: Managing General Partner interest in net income	354			1,738
Less: Managing General Partner interest in net income (loss)	9,936			(38,766		)	10,290		(37,028		)
Net income allocated to Investor Partners	$	1,417		$	6,953
Net income (loss) allocated to Investor Partners	$	39,742		$	(155,065	)	$	41,159	$	(148,112	)
Net income per Investor Partner unit	$	3		$	15
Net income (loss) per Investor Partner unit	$	84		$	(329	)	$	87	$	(314	)
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)

	Three months ended March 31,
	Six months ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	1,771		$	8,691
Net income (loss)	$	51,449		$	(185,140	)
Adjustments to net income to reconcile to net cash provided by operating activities:
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	4697,~~437~~009			60117,~~545~~952
Accretion of asset retirement obligations	37,~~799~~667			24,~~296~~626
Unrealized loss (gain) on derivative transactions	(24,524		)	25,083
Unrealized (gain) loss on derivative transactions	30,152			(8,236		)
Changes in assets and liabilities:
Decrease in accounts receivable	33,583			7,045
Accounts receivable	12,198			13,094
Decrease (increase) in crude oil inventory	11,570			(5,910		)
Crude oil inventory	6,943			(5,061		)
Increase in other assets	(1,611		)	(1,865		)
Other assets	(3,349		)	(3,728		)
Decrease in accounts payable and accrued expenses	(9,102		)	(2,340		)
Accounts payable and accrued expenses	(98,455		)	80,410
Decrease in Due to Managing General Partner - other, net	(54,816		)	(69,009		)
Due to Managing General Partner-other, net	(88,380		)	26,464
Net cash provided by operating activities	7,107			24,536
Net cash from operating activities	15,234			40,381
Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	—(534		)	(1115,~~816~~553		)
Net cash used in investing activities	—			(11,816		)
Net cash from investing activities	(534		)	(15,553		)
Cash flows from financing activities:
Distributions to Partners	(714,~~139~~765		)	(1224,~~677~~741		)
Net cash used in financing activities	(7,139		)	(12,677		)
Net cash from financing activities	(14,765		)	(24,741		)
Net increase (decrease) in cash and cash equivalents	(32		)	43
Net change in cash and cash equivalents	(65		)	87
Cash and cash equivalents, beginning of period	7,363			117,209
Cash and cash equivalents, end of period	~~7,331~~$	7,298		~~117,252~~$	117,296

See accompanying notes to unaudited condensed financial statements.

-42-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 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 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~~PDC ~~Development~~Energy, ~~Corporation~~Inc. (“PDC”), ~~which conducts business under the name PDC Energy,~~ to conduct and manage the Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of ~~March~~June 3130, 2012, there were 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 Investor Partners, which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through ~~March~~June 3130, 2012, the Managing General Partner ~~has~~had repurchased 29.5 units of Partnership interests from the Investor Partners at an average price of $3,818 per unit. As of ~~March~~June 3130, 2012, the Managing General Partner ~~owns~~owned 25% of the Partnership.

Beginning in June 2011, when the Investor ~~Partner~~Partners'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~~ 1,470 and $1,088 for the ~~three~~six months ended ~~March~~June 3130, 2012 and 2011, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02,. ~~which~~The ~~expires~~Managing inGeneral ~~April~~Partner's ~~2013. There~~obligation ~~were~~under noSection ~~Preferred~~4.02 ~~Cash~~expires ~~Distributions~~in ~~prior~~April ~~to June 2011~~2013. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions, to the Partnership's financial statements ~~that~~included ~~accompany~~in the 2011 Form 10-K.

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~~presentation of the Partnership's ~~financial~~results ~~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~~Quarterly ~~report~~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 2011 Form 10-K. The Partnership's accounting policies are described in the Notes to Financial Statements in the Partnership's 2011 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the three and six months ended ~~March~~June 3130, 2012, ~~and~~are ~~the cash flows for the same period, is~~ not necessarily indicative of the results to be expected for the full year or any other future period.

-5-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2012

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurement

On May 12, 2011, the Financial Accounting Standards Board ("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~~were effective for public entities during interim and annual periods beginning after December 15, 2011. ~~The~~ ~~adoption~~Adoption of these changes did not have a significant impact on the Partnership's financial statements.

-3-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2012

(unaudited)

Note 3−Transactions with Managing General Partner

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.:

	March 31, 2012			December 31, 2011
	June 30, 2012			December 31, 2011
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	1542,~~158~~317		$	40,289
Commodity price risk management, realized gain	2225,~~100~~975			6,118
Other (1)	(7370,~~011~~418		)	(136,913		)
Total Due to Managing General Partner-other, net	$	(352,~~753~~126	)	$	(90,506	)


(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-~~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 for the three and six months ended June 30, 2012 and 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 June 30,					Six months ended June 30,
	2012			2011		2012		2011
Well operations and maintenance⁽¹⁾	$	(43,133	)	$	129,972	$	27,346	$	155,942
Gathering, compression and processing fees	3,741			4,762		7,491		9,597
Direct costs - general and administrative	31,038			158,761		60,098		163,291
Cash distributions ^{(2) (3)}	1,198			1,770		2,300		4,711


(1)	Well operations and maintenance were reduced by approximately $89,000 in June 2012 compared to June 2011 as a result of the periodic review of environmental remediation liabilities. See Note 6, Commitments and Contingencies, for additional information.


(2)	Cash distributions include $428 and $817 during the three and six months ended June 30, 2012, respectively, and $445 and $851 during the three and six months ended June 30, 2011, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

(3)

Cash distributions to the Managing General Partner were reduced by $755 and $1,470 during the three and six months ended June 30, 2012, respectively, and $1,088 during the month ended June 30, 2011, 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.

-4-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 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 for the three months ended March 31, 2012 and 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 March 31,
	2012		2011
Well operations and maintenance	$	70,479	$	25,970
Gathering, compression and processing fees	3,750		4,835
Direct costs - general and administrative	29,060		4,530
Cash distributions (1) (2)	1,102		2,941

(1) Cash distributions include $389 and $406 during the three months ended March 31, 2012 and 2011, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

(2) Cash distributions to the Managing General Partner were reduced by $715 during the three months ended March 31, 2012, 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 in active markets.

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-~~The Managing General Partner validates its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and 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.

~~PDC~~The ~~2002-C~~Managing ~~LIMITED~~General ~~PARTNERSHIP~~Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also lenders in the Managing General Partner's corporate credit facility, 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 potential impact of nonperformance of its counterparties on the fair value of the Partnership's derivative instruments was not significant.

~~NOTES~~The TOPartnership's ~~UNAUDITED~~fixed-price ~~CONDENSED~~swaps ~~FINANCIAL~~and ~~STATEMENTS~~basis swaps are included in Level 2 and its natural gas collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, the Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

March 31, 2012



	Balance Sheet	June 30, 2012						December 31, 2011
	Line Item	Level 2		Level 3		Total		Level 2		Level 3		Total

Assets:

Current
Commodity based derivatives	Due from Managing General Partner-derivatives	$	177,879	$	3,244	$	181,123	$	176,059	$	5,887	$	181,946
Non-Current
Commodity based derivatives	Due from Managing General Partner-derivatives	77,854		—		77,854		144,180		—		144,180
Total assets		255,733		3,244		258,977		320,239		5,887		326,126

Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	77,648		—		77,648		79,281		—		79,281
Non-Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	36,110		—		36,110		71,474		—		71,474
Total liabilities		113,758		—		113,758		150,755		—		150,755
Net asset (1)		$	141,975	$	3,244	$	145,219	$	169,484	$	5,887	$	175,371

(~~unaudited~~1)As of June 30, 2012 and December 31, 2011, none of the Partnership's derivative instruments were designated as hedges.

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

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) monitoring changes in valuation methods and 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.



	Six months ended
	June 30, 2012			June 30, 2011
Fair value, net asset, beginning of period	$	5,887		$	10,169
Changes in fair value included in condensed statement of operations line item:
Commodity price risk management gain (loss), net	1,016			1,597
Settlements	(3,659		)	(8,992		)
Fair value, net asset, end of period	$	3,244		$	2,774

Change in unrealized gain (loss) relating to assets (liabilities) still held as of
June 30, 2012 and 2011, respectively, included in condensed statement of operations line item:
Commodity price risk management gain (loss), net	$	479		$	281

The ~~Managing~~significant ~~General~~unobservable ~~Partner~~input ~~has~~used ~~evaluated~~in the ~~credit~~fair ~~risk~~value measurement of the ~~counterparties~~Partnership's ~~holding the~~ derivative ~~assets,~~contracts ~~which~~is ~~are primarily financial institutions who are also major lenders in~~ the ~~Managing~~implied ~~General~~volatility ~~Partner's corporate credit facility agreement~~curve, ~~giving~~which ~~consideration~~is toprovided ~~amounts~~by ~~outstanding~~a ~~for~~third-party ~~each~~vendor. ~~counterparty~~A ~~and~~significant ~~the~~increase ~~duration~~or ofdecrease ~~each~~in ~~outstanding derivative position. Based on~~ the ~~Managing~~implied ~~General~~volatility, ~~Partner's~~in ~~evaluation~~isolation, ~~the~~would ~~Managing~~have ~~General~~a ~~Partner~~directionally ~~has~~similar ~~determined~~effect ~~that~~resulting ~~the~~in ~~impact~~a ofsignificantly ~~the~~higher ~~risk~~or oflower ~~nonperformance of the Managing General Partner's counterparties on the~~ fair value measurement of the Partnership's ~~derivative~~Level ~~instruments~~3 isderivative ~~insignificant~~contracts.

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.

	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

(1)As of March 31, 2012 and December 31, 2011, none of the Partnership's derivative instruments were designated as hedges.

-8-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2012

(unaudited)

	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		$	—

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.

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~~included in 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~~June 3130, 2012, the Partnership had derivative instruments in place for a portion of its anticipated natural gas production through 2013 ~~for~~totaling ~~a total of 83~~71,~~809~~202 ~~MMbtu~~MMBtu.

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

	Three months ended March 31,
	Three months ended June 30,
	2012									2011
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized ~~Gains~~Losses 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
Realized gains (losses)	$	39,970		$	(597	)	$	39,373		$	(936	)	$	843		$	(93	)
Unrealized gains (losses)	(2739,~~858~~970		)	52(14,~~382~~706		)	24(54,~~524~~676		)	~~(2,316~~936		)	~~(22~~32,~~767~~383		)	~~(25~~33,~~083~~319		)
Total commodity price risk management gain (loss), net	$	—		$	55,545		$	55,545		$	—		$	(21,856	)	$	(21,856	)
Total	$	—		$	(15,303	)	$	(15,303	)	$	—		$	33,226		$	33,226
	Six months ended June 30,
	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, net
Realized gains (losses)	$	55,504		$	14,890		$	70,394		$	6,574		$	(3,440	)	$	3,134
Unrealized gains (losses)	(55,504		)	25,352			(30,152		)	(6,574		)	14,810			8,236
Total	$	—		$	40,242		$	40,242		$	—		$	11,370		$	11,370

~~-9-~~Derivative Counterparties. The Managing General Partner's derivative arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions who are also lenders under the Managing General Partner's credit facility 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 potential impact of nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments was not significant.

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2012

(unaudited)

Derivative Counterparties. 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 risk of 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 oil and gas industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to 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~~These ~~three~~liabilities ~~months~~are ~~ended~~reduced ~~March 31,~~as ~~2012, there were no new environmental~~ remediation ~~projects~~efforts ~~identified~~are bycompleted ~~the~~or ~~Managing~~are ~~General~~adjusted ~~Partner~~as ~~for~~a ~~the~~consequence ~~Partnership. As~~ of ~~March 31,~~subsequent ~~2012,~~periodic ~~the~~reviews. ~~Partnership~~Liabilities ~~has~~for ~~accrued~~ environmental remediation ~~liabilities~~efforts ~~for~~are ~~two of the Partnership's wells in the amount of approximately $93,000, which is~~ 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 March 31, 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.

~~-10-~~In June 2012, as a result of the Managing General Partner's periodic review, the liability for environmental remediation efforts and environmental remediation expense was reduced by approximately $89,000 due to the determination that previously anticipated environmental remediation efforts are no longer required. This resulted in a negative environmental remediation expense of approximately $89,000 during the six months ended June 30, 2012. As of June 30, 2012 accrued environmental remediation liabilities were insignificant. As of December 31, 2011, accrued environmental remediation liabilities were approximately $99,000.

The Managing General Partner is not currently aware of any environmental claims existing as of June 30, 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.

-5-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~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 of the Partnership markets the Partnership's natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities and petroleum 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 to 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 PDC or third-party owned pipeline capacity, ~~owned~~due to high pressures in the gathering system whether caused by ~~PDC~~heat or ~~other~~ third-party ~~parties~~facilities issues, 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~~Partners'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~~Note 1, - General and Basis of Presentation, ~~and~~to ~~Item~~the 2unaudited -condensed financial statements included in this report and "Financial Condition, Liquidity and Capital Resources - Cash Flows" below for additional information and the effect of this modification on distributions.

Recent Developments

PDC -Sponsored Drilling Program Acquisition Plan

~~PDC,~~As ~~the~~ managing general partner of various public limited partnerships, PDC has disclosed its intention to pursue, beginning in the fall of 2010 and extending through 2013, the acquisition of the limited partnership units, 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~~the Partnership (the “Acquisition Plan”). For additional information regarding the Acquisition Plan, refer to ~~prior~~ disclosure included in PDC's prior 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 the Partnership's economic benefit.

During 2010 and 2011, PDC purchased ~~twelve~~12 partnerships for an aggregate amount of $107.7 million. The feasibility and timing of any future cash purchase offer by PDC to any additional partnership, including ~~this~~the 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 additional development in the Wattenberg Field, including commodity prices; and SEC reporting compliance status and timing and the ability to achieve all necessary SEC approvals required to commence a merger and repurchase offer. On December 21, 2011, PDC and its 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 Central District of California, and is titled Schulein v. 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.

On December 21, 2011, PDC and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders related to 11- partnership repurchases completed by mergers in 2010 and 2011. The action was filed in United States District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. On February 10, 2012, PDC filed a motion to dismiss, or in the alternative, to stay. On June 15, 2012, the Court denied the motion. The Court has approved a litigation schedule including a jury trial in May 2014.

-6-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

Additional 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 “Additional Development Plan”). The Additional 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~~formations which isare currently not producing. Under the Additional Development Plan, the Partnership plans to initiate 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.

Additional development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ~~ten~~10 years after initial well drilling so that well resources are optimally utilized. This additional development would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refracture or recomplete the individual wells and to determine the timing of any additional development activity. The timing of the refracturing or recompletion can be affected by the desire to optimize the economic return by additional development of the wells when commodity prices are at levels that are believed to provide the highest rate of return to the Partnership. On average, the production resulting from PDC's refracturings or recompletions have increased production; however, not all refracturings or recompletions have been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional development work is performed, the Partnership 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~~from 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 $180,000 and $260,000 per activity. As of ~~March~~June 3130, 2012, this Partnership had scheduled to complete 17 additional development opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $3.2 million and $3.6 million if all of the activities are performed. The Managing General Partner will continually evaluate the timing of commencing these 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 ~~March~~June 3130, 2012, no funds have been withheld from the Partnership's cash distributions pursuant to the Additional Development Plan.

Both the number and timing of the additional development activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on currently projected refracturing and recompletion costs and currently projected cash withholding, all scheduled Partnership 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 onupon their proportional ownership interest.

Implementation of the Additional 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 Additional Development Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the Additional Development Plan.

-127-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~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 in 2012, sustained low natural gas prices ~~would result in higher realized derivative gains upon settlement but also~~ could have a material adverse effect on the Partnership as a result of lower natural gas sales, a reduction in the estimated quantity of the Partnership's proved reserves and a corresponding reduction in 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 2320%, or approximately $3153,000, for the first ~~three~~six months of 2012 compared to the first ~~three~~six months of 2011, while sales volumes declined 118% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was approximately $5.1725 for the current year period compared to approximately $56.9804 for the same period a year ago. Realized derivative gains from natural gas sales contributed an additional $1.5371 per Mcfe, or approximately $3170,000, to the total revenues for the first ~~three~~six months of 2012 compared to an additional $0.1407, or approximately $3,000, from natural gas and crude oil sales for the first ~~three~~six months of 2011. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, increased to $6.7096 for the ~~current~~first ~~year~~six ~~three~~ months of 2012 from $6.1211 for the same ~~prior~~period ~~year~~of ~~period~~2011.

Natural ~~Gas~~gas, NGLs and ~~Crude~~crude ~~Oil~~oil ~~Production~~production ~~Costs~~costs ~~increased~~decreased by approximately $42139,000 during the six months ended June 30, 2012 ~~three~~compared ~~month~~to the same period in 2011, due primarily to an $89,000 reduction in environment remediation liabilities in June 2012 and the increased environmental remediation liabilities in June 2011 of $84,000, offset by increased workovers and tubing repair activities in 2012. ~~Direct~~ ~~costs~~The −reduction in environmental remediation liabilities in June 2012 was to reverse the accrual as it was determined that the liabilities recognized in June 2011 were completed for significantly less cost than anticipated. See Note 6, Commitments and Contingencies, for additional information. Direct costs-general and administrative ~~increased~~decreased by approximately $24103,000 during the 2012 ~~three~~six month period due to the timing of fees for professional services.

-138-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

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

	Three months ended March 31,
	Three months ended June 30,								Six months ended June 30,
	2012			2011			Change		2012		2011			Change
Number of gross producing wells (end of period)	13			14			(1	)	13		14			(1	)
Production(1)
Natural gas (Mcf)	1413,~~072~~533			1615,~~075~~510			(1213	)%	27,605		31,585			(13	)%
NGLs (Bbl)	~~385~~250			~~393~~373			(233	)%	635		766			(17	)%
Crude oil (Bbl)	~~651~~973			~~713~~673			(945	)%	1,624		1,386			17	%
Natural gas equivalents (Mcfe)(2)	20,~~288~~871			2221,~~711~~786			(114	)%	41,159		44,497			(8	)%
Average Mcfe per day	~~223~~229			~~252~~239			(124	)%	226		246			(8	)%
Natural Gas, NGLs and Crude Oil Sales
Natural gas, NGLs and crude oil sales
Natural gas	$	2818,~~282~~233		$	5349,~~437~~109		(4763	)%	$	46,515	$	102,546		(55	)%
NGLs	1512,~~525~~794			2019,~~370~~664			(2435	)%	28,319		40,034			(29	)%
Crude oil	6179,~~143~~972			6164,~~981~~147			(125	)%	141,115		126,128			12	%
Total natural gas, NGLs and crude oil sales	$	~~104~~110,~~950~~999		$	~~135~~132,~~788~~920		(2316	)%	$	215,949	$	268,708		(20	)%
Realized Gain (Loss) on Derivatives, net
Realized gain (loss) on derivatives, net
Natural gas	$	3139,~~021~~373		$	12,~~328~~612		~~152~~212	%	$	70,394	$	24,940		182	%
Crude oil	—			(912,~~101~~705		)	~~(100~~*	)%	—		(21,806		)	*
Total realized gain on derivatives, net	$	3139,~~021~~373		$	~~3,227~~(93	)	*		$	70,394	$	3,134		*
Average Selling Price (excluding realized gain (loss) on derivatives)
Average selling price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	21.0135		$	3.3217		(4057	)%	$	1.69	$	3.25		(48	)%
NGLs (per Bbl)	4051.3218			5152.8372			(223	)%	44.60		52.26			(15	)%
Crude oil (per Bbl)	9382.9219			8695.9332			8(14	)%	86.89		91.00			(5	)%
Natural gas equivalents (per Mcfe)	5.1732			56.9810			(13	)%	5.25		6.04			(13	)%
Average Selling Price (including realized gain (loss) on derivatives)
Average selling price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	4.2126		$	43.0998		37	%	$	4.24	$	4.04		5	%
NGLs (per Bbl)	4051.3218			5152.8372			(223	)%	44.60		52.26			(15	)%
Crude oil (per Bbl)	9382.9219			7476.1744			278	%	86.89		75.27			15	%
Natural gas equivalents (per Mcfe)	67.7020			6.1210			918	%	6.96		6.11			14	%
Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	3.92		$	1.67		135	%
Natural gas, NGLs and crude oil production cost(3)(4)	$	(1.89	)	$	6.50		*		$	0.97	$	4.03		(76	)%
Depreciation, depletion and amortization	$2.42	~~2.29~~		$2.64	~~2.67~~		(148	)%	2.36		2.65			(11	)%
Operating costs and expenses:
Operating costs and expenses
Direct costs - general and administrative	$	2931,~~060~~038		$	4158,~~530~~761		*(80	)%	$	60,098	$	163,291		(63	)%
Depreciation, depletion and amortization	$50,572	~~46,437~~		$57,407	~~60,545~~		(2312	)%	97,009		117,952			(18	)%
Cash distributions	$	7,~~139~~626		$	12,~~677~~064		(4437	)%	$	14,765	$	24,741		(40	)%

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

Amounts may not recalculate due to rounding.

-149-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~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) Represents natural gas, NGLs and crude oil operating expenses, ~~which~~including ~~include~~ production taxes.

⁽⁴⁾ Negative cost per Mcf for the three months ended June 30, 2012 is due to the reversal in June 2012 of environmental remediation liabilities recorded in June 2011 of approximately $89,000. The production rate per Mcf prior to the reversal is $2.39 and $3.14 for the three and six months ended June 30, 2012, respectively.

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

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

Btu - British thermal unit.

MBbl - One thousand barrels of crude oil or NGLs.

Mcf - One thousand cubic feet of natural gas volume.

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

MMBtu - One million British thermal units.

MMcf - One million cubic feet of natural gas volume.

MMcfe - One million cubic feet of natural gas equivalent.

Natural Gas, NGLs and Crude Oil Sales

Natural Gas, NGLs and Crude Oil Pricing. The Partnership's results of operations depend upon many factors, particularly the ~~price~~prices of natural gas, NGLs and crude oil and the Managing General Partner's ability to market the Partnership's production effectively. Natural gas, 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~~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.

The price the Partnership receives for its natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which generally includes natural gas sold at, near or below Colorado Interstate Gas (“CIG”) prices, as well as other nearby region prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is ~~primarily~~based on New York Mercantile Exchange~~, or~~ ("NYMEX,") ~~based~~prices. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential between NYMEX and CIG averaged $0.1219 and $0.2831 for the ~~three~~six months ended ~~March~~June 3130, 2012 and 2011, respectively.

~~Three~~Six months ended ~~March~~June 3130, 2012 as compared to ~~three~~six months ended ~~March~~June 3130, 2011

For the ~~three~~six months ended ~~March~~June 3130, 2012 compared to the same period inof 2011, natural gas, NGLs and crude oil sales volumes, on an energy equivalency-basis, decreased 118% due to normal production declines of 13%, for this stage in the wells'’ production life cycle, offset by increased sales from the Partnership's crude oil inventory.

The approximately $3153,000, or 2320%, decrease in sales for the 2012 ~~three~~six month period as compared to the prior year period was a reflection of sales volume decreases of 118% and a decline in average sales prices of 13%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.1725 for the current year ~~three~~six month period compared to $56.9804 for the same period a year ago.

Natural gas, and NGLs ~~and~~sales ~~crude~~for ~~oil~~the ~~sales~~six months ended June 30, 2012 decreased by 4755%, ~~24%~~ and 129%, respectively, as compared to the six months ended June 30, 2011, partially offset by an increase in crude oil sales of 12%. The ~~Partnership's~~decrease in natural gas sales ~~decrease~~ resulted from decreased ~~commodity~~ prices per Mcf of 4048% and lower ~~Partnership~~ natural gas production volumes of 1213%. The decrease in NGLs sales was due to a decrease of 217% in NGLs production volumes and to a decrease in the average commodity price per Bbl of 2215%. ~~The~~ ~~crude oil sales decrease was due primarily to sales volume decreases of 9%, partially offset by an increase in the average commodity price per Bbl of 8% during the current three month period.~~

-1510-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

~~Commodity~~The ~~Price~~crude ~~Risk~~oil ~~Management~~sales increase was due primarily to a sales volume increase of 17%, ~~Net~~partially offset by a decrease in the average commodity price per Bbl of 5%.

~~The~~Three ~~Partnership~~months ~~uses~~ended ~~various~~June ~~derivative instruments to manage fluctuations in natural gas prices. The Partnership has in place a variety of collars~~30, ~~fixed-price~~2012 ~~swaps~~as ~~and~~compared ~~basis swaps on a portion of the Partnership's estimated natural gas production. The Partnership sells its natural gas at similar prices~~ to ~~the~~three ~~indices~~months ~~inherent~~ended inJune ~~the Partnership's derivative instruments. As a result~~30, ~~for~~2011 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~~For ~~price~~the ~~risk~~three ~~management,~~months ~~net,~~ended ~~includes~~June ~~realized~~30, ~~gains~~2012 ~~and~~compared ~~losses and unrealized mark-~~to~~-market~~ ~~changes in~~ the ~~fair~~same ~~value~~period ofin ~~the~~2011, ~~derivative instruments related to the Partnership's~~ natural gas, NGLs and crude oil ~~production. See~~sales ~~Note 4~~volumes, ~~Fair~~on ~~Value~~an ~~Measurements~~energy ~~and~~equivalency-basis, ~~Disclosures~~decreased ~~and~~4% ~~Note~~due 5,to ~~Derivative~~production ~~Financial~~declines ~~Instruments~~of 17%, toconsidered ~~the~~normal ~~Partnership's~~for ~~unaudited~~this ~~condensed~~stage ~~financial~~in ~~statements~~the ~~included~~wells’ inproduction ~~this~~life ~~report~~cycle, ~~for~~offset ~~additional~~by ~~details~~increased ofsales from the Partnership's ~~derivative~~crude ~~financial~~oil ~~instruments~~inventory.

The ~~following~~approximately ~~table~~$22,000, ~~presents~~or 16%, decrease in sales for the ~~realized~~2012 ~~and~~three ~~unrealized~~month ~~derivative~~period ~~gains~~as compared to the prior year period was a reflection of sales volume decreases of 4% and ~~losses~~a ~~included~~decline in ~~commodity~~average sales price ~~risk~~of ~~management~~13%. ~~gain~~The average sales price per Mcfe, ~~net~~excluding the impact of realized derivative gains, was $5.32 for the current year three month period compared to $6.10 for the same period a year ago.

	Three months ended March 31,
	2012			2011
Commodity price risk management gain (loss), net:
Realized gains (losses)
Natural gas	$	31,021		$	12,328
Crude oil	—			(9,101		)
Total realized gains, net	31,021			3,227
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized gains	(27,858		)	(2,316		)
Unrealized gains (losses) for the period	52,382			(22,767		)
Total unrealized gains (losses), net	24,524			(25,083		)
Total commodity price risk management gain (loss), net	$	55,545		$	(21,856	)

Natural gas and NGLs sales for the three months ended June 30, 2012 decreased by 63% and 35%, respectively, as compared to the three months ended June 30, 2011, partially offset by an increase in crude oil sales of 25%. The decrease in natural gas sales resulted from decreased price per Mcf of 57% and lower natural gas production volumes of 13%. The decrease in NGLs sales was due to a decrease of 33% in NGLs production volumes and a decrease in the average commodity price per Bbl of 3%. The crude oil sales increase was due primarily to a sales volume increase of 45%, partially offset by a decrease in the average commodity price per Bbl of 14%.

~~Three~~Commodity ~~months~~Price ~~ended~~Risk ~~March 31, 2012 as compared to three months ended March 31, 2011~~Management

~~Realized~~The ~~gains~~Partnership ofused ~~approximately~~various ~~$31,000~~derivative ~~recognized~~instruments into ~~the~~manage ~~three~~fluctuations ~~months~~in ~~ended~~natural ~~March~~gas ~~31,~~and ~~2012,~~crude ~~were~~oil ~~primarily~~prices. ~~the~~The ~~result~~Partnership ofhad ~~lower~~in ~~natural~~place ~~gas~~collars, ~~spot~~fixed-price ~~prices~~swaps atand ~~settlement~~basis ~~compared~~swaps toon ~~the~~a ~~respective~~portion ~~strike price~~ of the Partnership's estimated natural gas ~~derivative~~and ~~positions. For~~crude ~~the~~oil ~~three~~production. ~~months~~The ~~ended~~Partnership ~~March~~sold ~~31,~~its ~~2012, realized gains on~~ natural gas, ~~exclusive~~and ofcrude ~~basis~~oil ~~swaps,~~at ~~were~~similar ~~approximately$54,000. These~~prices ~~gains~~to ~~were~~the ~~offset~~indices inherent in ~~part~~the byPartnership's ~~realized~~derivative ~~losses~~instruments. ofAs ~~approximately~~a ~~$23~~result,~~000~~ onfor the volumes underlying the Partnership's ~~basis~~derivative ~~swap~~ positions, as the ~~negative~~Partnership ~~basis~~ultimately ~~differential~~realized ~~between~~a ~~NYMEX~~price ~~and~~related ~~CIG~~to ~~weighted~~its ~~average~~collars ~~price~~of ~~was~~no ~~narrower~~less than the ~~strike~~floor ~~price~~and ofno more than the ceiling and, for the Partnership's ~~basis~~commodity swaps., the Partnership ultimately realized the fixed price related to its swaps.

~~Unrealized~~Commodity ~~gains~~price ofrisk ~~approximately~~management ~~$52,000~~includes ~~for~~realized ~~the~~gains ~~three~~and ~~months~~losses ~~ended~~and ~~March~~unrealized ~~31, 2012, were primarily related~~ mark-to-market ~~the~~changes ~~downward shift~~ in the ~~natural~~fair ~~gas~~value ~~forward~~of ~~curve~~the ~~and~~derivative ~~its~~instruments ~~impact~~related onto the ~~fair value of the~~ Partnership's ~~open~~natural ~~positions,~~gas ~~offset~~and incrude ~~part~~oil byproduction. ~~the~~See ~~narrowing~~Note of4, ~~the~~Fair ~~CIG~~Value ~~basis~~Measurements ~~forward~~and ~~curve.~~Disclosures, ~~For~~and ~~the~~Note ~~period~~5, ~~ended~~Derivative ~~March~~Financial 31Instruments, ~~2012,~~to ~~unrealized gains on~~ the ~~Partnership's~~unaudited ~~natural~~condensed ~~gas~~financial ~~positions~~statements ~~were~~included ~~approximately~~in ~~$52,000,~~this ~~offset~~report ~~slightly~~for byadditional ~~unrealized~~details ~~losses~~of on the Partnership's ~~CIG~~derivative ~~basis~~financial ~~swaps~~instruments.

~~Realized~~The ~~gains~~following ~~recognized~~table inpresents the ~~three~~realized ~~months~~and ~~ended~~unrealized ~~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 onand ~~natural~~losses ~~gas~~included ~~settlements were approximately $23,000 for the three months ended March 31, 2011. These gains were offset~~ in ~~part~~commodity ~~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 ofrisk ~~the~~management ~~basis~~gain ~~positions. The Partnership also realized an approximate $9~~(loss),~~000~~ ~~loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.~~ net:

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.



	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
Commodity price risk management gain (loss), net:
Realized gains (losses)
Natural gas	$	39,373		$	12,612		$	70,394		$	24,940
Crude oil	—			(12,705		)	—			(21,806		)
Total realized gains (losses), net	39,373			(93		)	70,394			3,134
Unrealized gains (losses)
Reclassification of realized losses (gains) included in
prior periods unrealized gains (losses)	(39,970		)	936			(55,504		)	(6,574		)
Unrealized gains (losses) for the period	(14,706		)	32,383			25,352			14,810
Total unrealized gains (losses), net	(54,676		)	33,319			(30,152		)	8,236
Total commodity price risk management gain (loss), net	$	(15,303	)	$	33,226		$	40,242		$	11,370

-1611-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

	Collars					Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/Index	Quantity(Gas-MMBtu(1))	Weighted AverageContract Price				Quantity(Gas-MMBtu(1))	WeightedAverageContractPrice		Quantity(Gas-MMBtu(1))	WeightedAverageContractPrice			Fair Value atMarch 31, 2012(2)
		Floors		Ceilings
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

Six months ended June 30, 2012 as compared to six months ended June 30, 2011

Realized gains of approximately $70,000 recognized in the six months ended June 30, 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. For the six months ended June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $113,000. These gains were offset in part by realized losses of approximately $43,000 on the Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of the Partnership's basis swaps.

Unrealized gains of approximately $25,000 for the six months ended June 30, 2012 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of the Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. For the period ended June 30, 2012, unrealized gains on the Partnership's natural gas positions were approximately $29,000, offset by unrealized losses on the Partnership's CIG basis swaps of approximately $4,000.

Realized gains recognized in the six months ended June 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 $57,000 for the six months ended June 30, 2011. These gains were offset in part by an approximate $32,000 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 a loss of approximately $22,000 on its crude oil positions due to higher spot prices at settlement compared to the respective strike price.

Unrealized gains during the six months ended June 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 $28,000 which was partially offset by unrealized losses of approximately $11,000 on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow. Additionally, the shifts upward in the crude oil curves resulted in an unrealized loss of approximately $2,000.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

Realized gains of approximately $39,000 recognized in the three months ended June 30, 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. For the three months ended June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $59,000. These gains were offset in part by realized losses of $20,000 on the Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of the Partnership's basis swaps.

Unrealized losses of approximately $15,000 for the three months ended June 30, 2012 were primarily related to the upward shift in the natural gas forward curve and its impact on the fair value of the Partnership's open positions and by the narrowing of the CIG basis forward curve. For the period ended June 30, 2012, unrealized losses on the Partnership's natural gas positions were approximately $12,000 in addition to unrealized losses on the Partnership's CIG basis swaps of approximately $3,000.

Realized gains recognized in the three months ended June 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 June 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 a loss of approximately $13,000 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 June 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 shift downward in the crude oil curve resulted in an unrealized gain of approximately $9,000 during the three months ended June 30, 2011. Likewise, the shifts downward in the natural gas and basis curves resulted in a total unrealized gain of approximately $23,000.

-12-

Index

PDC 2002-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table presents the Partnership's derivative positions in effect as of June 30, 2012:



	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 June 30, 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 June 30, 2012⁽²⁾

Natural Gas
NYMEX
07/01 - 09/30/2012	512	$	6.00	$	8.27	11,990	$	6.98	12,502	$	(1.88	)	$	31,011
10/01 - 12/31/2012	562	6.00		8.27		11,672	6.98		12,234	(1.88		)	25,949
01/01 - 03/31/2013	—	—		—		11,752	7.12		11,752	(1.88		)	22,690
04/01 - 06/30/2013	—	—		—		11,706	7.12		11,706	(1.88		)	23,825
07/01 - 09/30/2013	—	—		—		11,620	7.12		11,620	(1.88		)	22,509
10/01 - 12/31/2013	—	—		—		11,388	7.12		11,388	(1.88		)	19,235
Total	1,074					70,128			71,202				$	145,219

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

(2) As of ~~March 31~~June 30, 2012, approximately 2% of the fair value of the Partnership's derivative assets were measured using significant unobservable inputs (Level 3);. ~~see~~See Note 4, Fair Value Measurements and Disclosures, to the ~~accompanying~~ unaudited condensed financial statements included in this report.

Natural Gas, NGLs and Crude Oil Production Costs

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

~~Three~~Six months ended ~~March~~June 3130, 2012 as compared to ~~three~~six months ended ~~March~~June 3130, 2011

~~Production~~Natural ~~and~~gas, ~~operating~~NGLs ~~costs~~and ~~for~~crude ~~the~~oil ~~three~~production ~~month~~costs ~~period~~decreased ~~ended~~by ~~March~~approximately 31$139,000 ~~2012~~during ~~increased~~the bysix ~~approximately~~months ~~$42~~ended June 30,~~000~~ 2012 compared to the same period in 2011~~. Lease~~, ~~operating~~due ~~costs~~primarily ~~were~~to ~~higher~~an ~~by approximately~~ $4789,000 reduction in ~~the~~environment ~~current~~remediation ~~period~~liabilities asin ~~workovers~~June 2012 and ~~tubing~~the ~~repair~~increased ~~activities~~environmental ~~collectively~~remediation ~~were~~liabilities ~~lower~~ in ~~the~~June ~~prior~~2011 ~~period. Higher~~of ~~lease~~$84,000, ~~operating costs were partially~~ offset by ~~lower~~increased ~~revenue~~workovers and ~~volume-based~~tubing ~~costs~~repair byactivities ~~approximately $3,000~~ in 2012,. ~~consistent~~The ~~with~~reduction ~~sales~~in ~~and~~environmental ~~production~~remediation ~~declines~~liabilities ~~from~~in ~~2011.~~June ~~Production~~2012 ~~and~~was ~~operating~~to ~~costs~~reverse ~~per~~the ~~Mcfe~~accrual ~~increased~~as toit ~~$3.92~~was ~~during~~determined ~~2012~~that ~~from~~the ~~$1.67~~liabilities recognized in June 2011 ~~due~~were tocompleted ~~lower~~for ~~volumes~~significantly ~~and~~less ~~increased~~cost ~~costs~~than anticipated.

~~Direct~~Three ~~Costs−General~~months ~~and~~ended ~~Administrative~~June 30, 2012 as compared to three months ended June 30, 2011

~~Three~~Natural gas, NGLs and crude oil production costs decreased by approximately $181,000 during the three months ended ~~March~~June 3130, 2012 as compared to the same period in 2011, due primarily to an $89,000 reduction in environment remediation liabilities in June 2012 and the increased environmental remediation liabilities in June 2011 of $84,000. The reduction in environmental remediation liabilities in June 2012 was to reverse the accrual as it was determined that the liabilities recognized in June 2011 were completed for significantly less cost than anticipated. The environmental remediation liability reversal in 2012 reduced production and operating costs per Mcfe by $4.28 and $2.17 for the three and six months ended ~~March~~June 3130, 2012. The environmental remediation liability recorded in 2011 increased production and operating costs per Mcfe by $3.86 and $1.89 for the three and six months ended June 30, 2011. See Note 6, Commitments and Contingencies, for additional information.

~~Direct costs~~ - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs increased during the three months ended March 31, 2012, compared to the same period in 2011, by approximately $24,000, principally due to the timing of fees for professional services. 13-

-17-

Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

~~Depreciation,~~Direct ~~Depletion~~Costs-General and ~~Amortization (DD&A)~~Administrative

~~Three~~Six months ended ~~March~~June 3130, 2012 as compared to ~~three~~six months ended ~~March~~June 3130, 2011

~~The~~Direct ~~DD&A~~costs-general ~~expense~~and ~~rate~~administrative ~~per~~consist ~~Mcfe~~primarily ~~decreased~~of toprofessional ~~$2.29~~fees for ~~the~~financial ~~2012~~statement ~~three~~audits, ~~month~~income ~~period,~~tax ~~compared~~return topreparation, ~~$2.67~~independent ~~during~~engineers' ~~the~~reserve ~~same~~reports ~~period~~and inlegal ~~2011~~matters. ~~The~~Direct ~~decrease~~costs-general inand administrative decreased during the ~~per~~six ~~Mcfe~~months ~~rates~~ended ~~for~~June ~~the~~30, 2012 ~~period~~ compared to the ~~2011~~same period isin ~~due to the effect of the~~ 2011 ~~impairment~~by ~~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 $14103,000, ~~for~~principally ~~the~~due ~~2012~~to ~~three~~the ~~month~~timing ~~period~~of ~~compared~~fees tofor ~~the~~professional ~~same 2011 period~~services.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

Direct costs-general and administrative decreased during the three months ended June 30, 2012 compared to the same period in 2011 by approximately $128,000, principally due to the timing of fees for professional services.

Depreciation, Depletion and Amortization ("DD&A")

Six months ended June 30, 2012 as compared to six months ended June 30, 2011

The DD&A expense rate per Mcfe decreased to $2.36 for the six months ended June 30, 2012, compared to $2.65 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 decreases in production and DD&A expense rate resulted in an overall decreased DD&A expense of approximately $21,000 for the 2012 six months compared to the same 2011 period.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

The DD&A expense rate per Mcfe decreased to $2.42 for the three months ended June 30, 2012, compared to $2.64 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 decreases in production and DD&A expense rate resulted in an overall decreased DD&A expense of approximately $7,000 for the 2012 three months compared to the same 2011 period.

Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for the ~~three~~six months ended ~~March~~June 3130, 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, direct costs - general and administrative ~~activities~~ and ~~provided~~ monthly distributions to the Investor Partners and ~~PDC,~~ the Managing General Partner. Any future withholdings would provide the funding for planned Wattenberg Field refracturing or recompletion costs to be incurred during 2013 and thereafter, and are expected to decrease distributions from historical levels.

Fluctuations in the Partnership's operating cash flows are substantially driven by changes in commodity prices, insales ~~production~~ volumes and in realized gains and losses from commodity ~~positions~~contracts. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through the use of derivatives. Therefore, the primary source of ~~the Partnership's~~ cash ~~flow~~flows 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~~The Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership's expected future production from producing wells, and therefore may still experience significant fluctuations in cash flows from operations. As of ~~March 31~~June 30, 2012, the Partnership had natural gas derivative positions in place covering 85% of the expected natural gas production for the remainder of 2012, at an average price of $5.0706 per Mcf. ~~However,~~ ~~the~~The Partnership has no NGL or crude oil derivatives. 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 2012 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the 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 Development Plan.

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Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances, decreased production would have a material adverse 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 2012 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the additional development activities which are more fully described in Recent Developments−Additional Development Plan above.

Working Capital

~~The~~At June 30, 2012, the Partnership had a working capital surplus of approximately $38160,000 ~~at March 31, 2012~~ compared to a working capital deficit of approximately $8,000 at December 31, 2011,. anThe increase of approximately $46168,000~~. The~~ ~~increase~~ was primarily due to the following changes:

• ~~Accounts~~accounts receivable decreased by approximately $5910,000 between ~~March~~June 3130, 2012 and December 31, 2011.;

• ~~Realized~~realized and unrealized derivative gains receivable increased by approximately $4321,000 between ~~March~~June 3130, 2012 and December 31, 2011.;

• ~~Oil~~oil inventory decreased by approximately $117,000 between ~~March~~June 3130, 2012 and December 31, 2011.;

• ~~Due~~amounts due to Managing General Partner-other, net, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, decreased by approximately $6466,000 between ~~March~~June 3130, 2012 and December 31, 2011.; and

• ~~Accounts~~accounts payable decreased by approximately $998,000 between ~~March~~June 3130, 2012, and December 31, 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~~ Operating Activities

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

The Partnership currently uses the "net-back" method of accounting for recording natural gas sales. Under this method, 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~~prices that isare below the ~~indices~~related ~~for~~pricing ~~which the production is based~~indices.

Net cash ~~provided~~flows byfrom operating activities ~~was~~were approximately $715,000 for the ~~three~~six months ended ~~March~~June 3130, 2012, compared to approximately $2440,000 for the comparable period in 2011. The decrease of approximately $1725,000 in ~~net~~ cash provided by operating activities was due primarily to the following:

• Ana ~~increase~~decrease in natural gas, NGLs and crude oil sales receipts of approximately $1978,000~~, or 13%,~~;

• Aan ~~decrease~~increase in commodity price risk management realized ~~gains~~gain receipts of approximately $231,000,; ~~or 14%,~~ and

• Ana ~~increase~~decrease in production costs and direct costs - general and administrative payments of approximately $3422,000.

~~Cash Flows from~~ Investing Activities

~~The~~From ~~Partnership,~~time ~~from~~to time~~-to-time~~, the Partnership 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~~six months ended ~~March~~June 3130, 2012 and 2011, respectively.

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Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

~~Cash Flows from~~ Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2003 and has distributed $9.6 million through ~~March~~June 3130, 2012. 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 for its 20% general partner interest in the Partnership. and Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership, ~~and~~as ~~include~~well as amounts distributed to ~~PDC~~the Managing General Partner for limited partnership units repurchased.

Distributions
Three months ended March 31,	Managing General Partner		Investor Partners		Total
Three months ended June 30,	Managing General Partner		Investor Partners		Total
2012	$	~~713~~770	$	6,~~426~~856	$	7,~~139~~626
2011	21,~~535~~325		10,~~142~~739		12,~~677~~064
Six months ended June 30,	Managing General Partner		Investor Partners		Total
2012	$	1,483	$	13,282	$	14,765
2011	3,860		20,881		24,741

The decrease in total distributions for 2012 as compared to 2011 is primarily due to the decrease in cash flows from operating activities during 2012, partially offset by a decrease in capital expenditures for natural gas and crude oil properties.

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~~1,470 and $1,088 for the ~~three~~six months ended ~~March 31~~June 30, 2012 and 2011, respectively, 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.

Off-Balance Sheet Arrangements

As of ~~March~~June 3130, 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 2011 Form 10-K.

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Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~PARTNERSHIP

(A West Virginia Limited Partnership)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of ~~March~~June 3130, 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 ~~March~~June 3130, 2012.

(b) Changes in Internal Control over Financial Reporting

During the three months ended ~~March~~June 3130, 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.

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Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~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~~in May 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~~There ~~following~~were ~~table~~no ~~presents~~limited ~~information~~partnership ~~about~~units ~~the~~repurchased ~~Managing~~by ~~General~~PDC ~~Partner's~~for ~~limited partner unit repurchases during~~ the three months ended ~~March~~June 3130, 2012.

Period	Total Number of Units Repurchased	Average Price Paid Per Unit
January 1 - 31		$	—
February 1 - 29	2.91	229
March 1 - 31	—	—
Total first quarter repurchases	2.91

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

~~Not applicable~~None.

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Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~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.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

31.1

Certification by Chief Executive Officer of PDC Energy, Inc., 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 PDC Energy, Inc., 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 PDC Energy, Inc., 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.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

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.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

*Furnished herewith.

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Index

PDC 2002-C ~~Limited~~LIMITED ~~Partnership~~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), Inc.

By: /s/ James M. Trimble James M. TrimblePresident and Chief Executive Officerof ~~Petroleum Development Corporation (dba~~ PDC Energy), ~~May~~Inc. 14August 13, 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	~~May~~August 1413, 2012
James M. Trimble	~~Petroleum Development Corporation (dba~~ PDC Energy), Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~May~~August 1413, 2012
Gysle R. Shellum	~~Petroleum Development Corporation (dba~~ PDC Energy), Inc. Managing General Partner of the Registrant
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~May~~August 1413, 2012
R. Scott Meyers	~~Petroleum Development Corporation (dba~~ PDC Energy), Inc. Managing General Partner of the Registrant
	(principal accounting officer)

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Filing Compare · PDC 2002 C LTD PARTNERSHIP