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, 2013

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

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 333-47622-03

PDC 2002-C Limited Partnership

(Exact name of registrant as specified in its charter)



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

1775 Sherman Street, Suite 3000

Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

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

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, 2013 this Partnership had 471.91 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2002-C Limited Partnership

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements
	Condensed Balance Sheets (unaudited)	32
	Condensed Statements of Operations (unaudited)	43
	Condensed Statements of Cash Flows (unaudited)	54
	Notes to Unaudited Condensed Financial Statements	65
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1312
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	Controls and Procedures	21
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	22
Item 1A.	Risk Factors	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
Item 3.	Defaults Upon Senior Securities	22
Item 4.	Mine Safety Disclosures	22
Item 5.	Other Information	22
Item 6.	Exhibits	23
	SIGNATURES	24

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly 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 this Partnership's business, financial condition and results of operations. PDC Energy, Inc. (“PDC”) is the Managing General Partner of this 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 ("U.S.") 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 relate to, among other things: estimated crude oil, natural gas, and natural gas liquids ("NGLs") ~~and crude oil~~ reserves; ~~additional development plans;~~ future production, expenses, cash flows and liquidity; anticipated capital expenditures and projects; availability of additional midstream facilities and services in the Wattenberg Field and timing and benefits of that availability; the ~~adequacy of this Partnership's insurance; the~~ effectiveness of the Managing General Partner's derivative program in providing a degree of price stability; ~~closing of~~ and ~~expected proceeds from this Partnership's pending asset disposition; 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~~crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude oil~~NGLs, 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~~crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude oil~~NGLs;


•	the impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;

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


•	changes in estimates of proved reserves;


•	inaccuracy of reserve estimates and expected production rates;


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


•	availability of future cash flows for investor distributions or funding of development activities;


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


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


•	timing and receipt of necessary regulatory permits;

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


•	this Partnership's future cash flows, liquidity and financial condition;


•	competition in the oil and gas industry;


•	availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport this Partnership's production, particularly in the Wattenberg Field, and the impact of these facilities on the price this Partnership receives for its production;

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

• effect of natural gas derivative activities;


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


•	cost of pending or future litigation;

• ~~potential obstacles to completing this Partnership's pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other~~ adjustments relating to ~~those~~asset ~~transactions~~dispositions that may be unfavorable to this Partnership;


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


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

- 1-

Further, this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Quarterly Report on Form 10-Q, this Partnership's Annual Report on Form 10-K for the year ended December 31, 2012(“2012 Form 10-K”) filed with the U.S. Securities and Exchange Commission (“SEC”) on March 15, 2013 and this Partnership's other filings with the SEC for further information on risks and uncertainties that could affect this Partnership's business, financial condition, results of operations and cash flows. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. This 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.

- 21-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

PDC 2002-C Limited Partnership

Condensed Balance Sheets

(unaudited)

	March 31, 2013			December 31, 2012*
	June 30, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	87458,~~202~~434		$	7,234
Accounts receivable	3614,~~206~~647			39,042
Crude oil inventory	119,~~977~~399			14,763
Due from Managing General Partner-derivatives	~~103,578~~—			165,345
Total current assets	~~238~~482,~~963~~480			226,384
Natural gas and crude oil properties, successful efforts method, at cost	6,755,502			6,969,870
Crude oil and natural gas properties, successful efforts method, at cost	6,758,048			6,969,870
Less: Accumulated depreciation, depletion and amortization	(4,~~958~~990,~~454~~136		)	(5,062,654		)
Natural gas and crude oil properties, net	1,797,048			1,907,216
Crude oil and natural gas properties, net	1,767,912			1,907,216
Assets held for sale	64,785			—
Other assets	51,722			48,776
Other assets	50,321			48,776
Total Assets	$	2,302,114		$	2,182,376
Total Assets	$	2,151,117		$	2,182,376
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	317,~~070~~156		$	4,788
Due to Managing General Partner-derivatives	~~55,594~~—			75,194
Due to Managing General Partner-other, net	~~100~~85,~~176~~486			26,146
Total current liabilities	~~158~~102,~~840~~642			106,128
Asset retirement obligations	~~200~~204,~~981~~528			236,768
Liabilities held for sale	39,869			—
Total liabilities	307,170			342,896
Total liabilities	399,690			342,896
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	~~364~~414,~~415~~397			377,332
Limited Partners - 471.91 units issued and outstanding	1,~~387~~580,~~012~~547			1,462,148
Total Partners' equity	1,~~751~~994,~~427~~944			1,839,480
Total Liabilities and Partners' Equity	$	2,~~151~~302,~~117~~114		$	2,182,376

*Derived from audited 2012 balance sheet

See accompanying notes to unaudited condensed financial statements.

- 32-

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,
	2013			2012			2013			2012
Revenues:
Natural gas, NGLs and crude oil sales	$	65,257		$	87,794
Crude oil, natural gas and NGLs	$	42,722		$	99,953		$	107,979		$	187,747
Commodity price risk management gain (loss), net	~~(18~~5,~~343~~069		)	55(15,~~545~~303		)	(13,274		)	40,242
Total revenues	4647,~~914~~791			~~143~~84,~~339~~650			94,705			227,989
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	22,168			67,639
Crude oil, natural gas and NGLs production costs	49,729			(48,709		)	71,897			18,930
Direct costs - general and administrative	3032,~~863~~600			2931,~~060~~038			63,463			60,098
Depreciation, depletion and amortization	4231,~~003~~682			4347,~~580~~840			73,685			91,420
Accretion of asset retirement obligations	3,~~482~~548			3,~~234~~295			7,030			6,529
Total operating costs and expenses	98117,~~516~~559			~~143~~33,~~513~~464			216,075			176,977
Loss from continuing operations	(51,602		)	(174		)
Income (loss) from operations	(69,768		)	51,186			(121,370		)	51,012
Interest income	547			43			52			7
Income from discontinued operations	3,008			1,941
Income (loss) from continuing operations	(69,721		)	51,189			$	(121,318	)	$	51,019
Net income (loss)	$	(48,589	)	$	1,771
Income (loss) from discontinued operations	328,836			(1,511		)	331,844			430
Net income (loss) allocated to partners	$	(48,589	)	$	1,771
Net income	$	259,115		$	49,678		$	210,526		$	51,449
Less: Managing General Partner interest in net income (loss)	(9,718		)	354
Income (loss) from continuing operations	$	(69,721	)	$	51,189		$	(121,318	)	$	51,019
Net income (loss) allocated to Investor Partners	$	(38,871	)	$	1,417
Less: Managing General Partner interest in income (loss) from continuing operations	(13,944		)	10,238			(24,264		)	10,204
Net income (loss) per Investor Partner unit	$	(82	)	$	3
Income (loss) from continuing operations allocated to Investor Partners	$	(55,777	)	$	40,951		$	(97,054	)	$	40,815
Investor Partner units outstanding	471.91			471.91
Income (loss) from discontinued operations	$	328,836		$	(1,511	)	$	331,844		$	430
Less: Managing General Partner interest in income (loss) from discontinued operations	65,767			(302		)	66,369			86
Income (loss) from discontinued operations allocated to Investor Partners	$	263,069		$	(1,209	)	$	265,475		$	344
Net income (loss) per Investor Partner unit
Continuing operations	$	(118	)	$	87		$	(206	)	$	86
Discontinued operations	557			(3		)	563			1
Net income per Investor Partner unit	$	439		$	84		$	357		$	87
Investor Partner units outstanding	471.91			471.91			471.91			471.91

See accompanying notes to unaudited condensed financial statements.

- 43-

PDC 2002-C Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Three months ended March 31,
	Six months ended June 30,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	(48,589	)	$	1,771
Net income	$	210,526		$	51,449
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Adjustments to net income to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	4577,~~383~~065			4697,~~437~~009
Accretion of asset retirement obligations	48,~~082~~035			37,~~799~~667
Unrealized (gain) loss on derivative transactions	42,167			(24,524		)
Change in unrealized loss on derivative transactions	71,195			30,152
Gain on sale of crude oil and natural gas properties	(347,493		)	—
Changes in assets and liabilities:
Accounts receivable	224,~~836~~395			3312,~~583~~198
Crude oil inventory	24,~~786~~120			116,~~570~~943
Other assets	(12,~~545~~946		)	(13,~~611~~349		)
Accounts payable and accrued expenses	(12,~~718~~940		)	(998,~~102~~455		)
Due to Managing General Partner-other, net	7464,~~030~~122			(5488,~~816~~380		)
Net cash from operating activities	~~119~~106,~~432~~079			715,~~107~~234
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	—			(534		)
Proceeds from sale of crude oil and natural gas properties	400,183			—
Net cash from investing activities	400,183			(534		)
Cash flows from financing activities:
Distributions to Partners	(3955,~~464~~062		)	(714,~~139~~765		)
Net cash from financing activities	(3955,~~464~~062		)	(714,~~139~~765		)
Net change in cash and cash equivalents	79451,~~968~~200			(3265		)
Cash and cash equivalents, beginning of period	7,234			7,363
Cash and cash equivalents, end of period	$	87458,~~202~~434		$	7,~~331~~298
Supplemental disclosure of non-cash activity:
Change in accounts payable and accrued expenses related to disposition of properties and equipment	$	(15,308	)	$	—
Change in due from managing general partner-other,net related to disposition of properties and equipment	4,782			—

See accompanying notes to unaudited condensed financial statements.

- 54-

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

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2013

(unaudited)

Note 1 - General and Basis of Presentation

PDC 2002-C Limited Partnership (“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~~crude ~~gas~~oil and ~~crude~~natural ~~oil~~gas properties. Business operations commenced upon closing of an offering for the sale of Partnership units. Upon funding, this Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes PDC Energy, Inc. (“PDC”) to conduct and manage this 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 this Partnership and initiates and completes substantially all Partnership transactions.

As of ~~March~~June 3130, 2013, there were 467 limited partners in this Partnership (the “Investor Partners”). PDC is the designated Managing General Partner of this Partnership and owns a 20% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 80% to the Investor Partners, which are shared pro rata based upon the number of units in this 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, 2013, the Managing General Partner had repurchased 3132.64 units of Partnership ~~interests~~interest from the Investor Partners at an average price of $3,~~578~~510 per unit. As of ~~March~~June 3130, 2013, the Managing General Partner owned 25.45% of this Partnership.

Beginning in June 2011, when the Investor Partners' average annual rate of return fell below 12.8%, this 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 $45,~~694~~983 and $~~715~~1,470 for the ~~three~~six months ended ~~March~~June 3130, 2013 and 2012, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02. The Managing General Partner's obligation under Section 4.02 ~~expires~~expired in April 2013. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions, to this Partnership's financial statements included in the 2012 Form 10-K.

In the Managing General Partner's opinion, the accompanying unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of this Partnership's results 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 SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with this Partnership's audited financial statements and notes thereto included in this Partnership's 2012 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2012 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, 2013 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are mainly attributable to reporting as discontinued operations the results of operations related to the ~~planned~~ sale of this Partnership's Piceance Basin assets. See Note 8, Divestitures and Discontinued Operations, for additional information regarding the divestiture. The reclassifications had no impact on previously reported cash flows, net income or Partners’ equity. ~~See Note 8, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned divestiture.~~

- 6-

PDC 2002-C Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2013

(unaudited)

Note 2 - Summary of Significant Accounting Policies

Recently Adopted Accounting ~~Standards~~Standard

On January 1, 2013, this Partnership adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. This Partnership's adoption of these changes had no impact on the unaudited condensed financial statements.

- 5-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2013

(unaudited)

Note 3 - Transactions with Managing General Partner

The Managing General Partner transacts business on behalf of this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of this Partnership are distributed to the Partners net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership. The fair value of this Partnership's portion of open derivative instruments iswere 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 this Partnership's investors as of the dates indicated:

	March 31, 2013			December 31, 2012
	June 30, 2013			December 31, 2012
Natural gas, NGLs and crude oil sales revenues collected from this Partnership's third-party customers	$	15,970		$	23,794
Crude oil, natural gas and NGLs sales revenues collected from this Partnership's third-party customers	$	22,330		$	23,794
Commodity price risk management, realized gain	1510,~~744~~922			13,174
Other (1)	(~~131~~118,~~890~~738		)	(63,114		)
Total Due to Managing General Partner-other, net	$	(~~100~~85,~~176~~486	)	$	(26,146	)


(1)	All other unsettled transactions, excluding derivative instruments, between this 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.

-The 7-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, 2013 and 2012. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the condensed statements of operations for continuing operations or in Note 8, Divestitures and Discontinued Operations, for discontinued operations.

PDC 2002-C Limited Partnership



	Three months ended June 30,					Six months ended June 30,
	2013		2012			2013		2012
Well operations and maintenance	$	56,792	$	(43,133	)	$	88,976	$	27,346
Gathering, compression and processing fees	2,167		3,741			4,710		7,491
Direct costs - general and administrative	64,440		31,038			95,303		60,098
Cash distributions ^{(1) (2)}	2,782		1,198			8,397		2,300


(1)	Cash distributions include $941 and $3,357 during the three and six months ended June 30, 2013, respectively, and $428 and $817 during the three and six months ended June 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

(2)

Cash distributions to the Managing General Partner were reduced by $1,289 and $5,983 during the three and six months ended June 30, 2013, respectively, and $755 and $1,470 for the three and six months ended June 30, 2012, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

- 6-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2013

(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, 2013 and 2012. “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 for continuing operations and in Note 8, Assets Held for Sale, Divestitures and Discontinued Operations, for discontinued operations.

	Three months ended March 31,
	2013		2012
Well operations and maintenance	$	32,184	$	70,479
Gathering, compression and processing fees	2,543		3,750
Direct costs - general and administrative	30,863		29,060
Cash distributions (1) (2)	5,615		1,102

(1) Cash distributions include $2,416 and $389 during the three months ended March 31, 2013 and 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

(2) Cash distributions to the Managing General Partner were reduced by $4,694 and $715 during the three months ended March 31, 2013 and 2012, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

Note 4 - Fair Value of Financial Instruments

Determination of fair value. This Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires this 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. In these cases, 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) 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 quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

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

The Managing General Partner measures the fair value of this 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 forward curve, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

-The 8-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 2002~~-C ~~Limited Partnership~~7-

PDC 2002-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2013

(unaudited)

~~The~~This ~~Managing~~Partnership's ~~General~~fixed-price ~~Partner~~swaps ~~validates its fair value measurement through the review of counterparty statements~~ and ~~other~~basis ~~supporting~~swaps ~~documentation,~~as ~~the determination that the source~~ of ~~the~~December ~~inputs is valid~~31, ~~the~~2012 ~~corroboration~~were ofincluded ~~the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes~~ in ~~valuation~~Level ~~methods and assumptions~~2. ~~While~~The ~~the~~following ~~Managing~~table ~~General~~presents ~~Partner~~this ~~uses common industry practices to develop its valuation techniques, changes in the Managing General Partner~~Partnership's ~~pricing~~derivative ~~methodologies~~assets ~~or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate~~ and ~~consistent~~liabilities ~~with~~that ~~those~~had ~~used~~been bymeasured ~~other~~at ~~market participants, the use of a different methodology or assumptions to determine the~~ fair value ofon ~~certain financial instruments could result in~~ a ~~different~~recurring ~~estimate of fair value.~~basis:

The Managing General Partner's derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. The Managing General Partner has elected not to offset the fair value positions recorded on the unaudited condensed balance sheets for this Partnership.



	Balance Sheet
	Line Item	Level 2

Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	165,345
Total assets		165,345

Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	75,194
Total liabilities		75,194
Net asset		$	90,151

~~This~~Derivative ~~Partnership's~~instruments ~~fixed-price~~that ~~swaps~~were ~~and~~due ~~basis~~to ~~swaps~~mature ~~are~~subsequent ~~included~~to inJune 30, ~~Level~~2013 2were liquidated during the quarter ended June 30, 2013. ~~The~~Accordingly, ~~following~~as ~~table~~of ~~presents~~June 30, 2013, this Partnership's ~~derivative~~did ~~assets~~not ~~and~~have ~~liabilities~~any ~~measured~~derivative atinstruments ~~fair~~in ~~value~~place onfor aits ~~recurring~~future ~~basis:~~production.

	Balance Sheet	March 31, 2013		December 31, 2012
	Line Item	Level 2		Level 2
Assets:
Current
Commodity-based derivatives	Due from Managing General Partner-derivatives	$	103,578	$	165,345
Total assets		103,578		165,345
Liabilities:
Current
Basis protection derivative contracts	Due to Managing General Partner-derivatives	55,594		75,194
Total liabilities		55,594		75,194
Net asset		$	47,984	$	90,151

Non-Derivative Financial Assets and Liabilities

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

~~Note 5~~ - ~~Derivative Financial Instruments~~8-

AsPDC of2002-C ~~March 31,~~LIMITED 2013, this Partnership had derivative instruments in place for all of its anticipated 2013 natural gas production totaling 34,714 MMBtu. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes. PARTNERSHIP

- 9-

PDC 2002-C Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2013

(unaudited)

Note 5 - Derivative Financial Instruments

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

	Three months ended March 31,
	Three months ended June 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) ~~Included~~included in Prior Periods Unrealized			Realized ~~and~~Gains ~~Unrealized~~for ~~Losses For~~ the Current Period			Total			Reclassification of Realized Gains (Losses) ~~Included~~included in Prior Periods Unrealized			Realized and Unrealized ~~Gains~~Losses ~~For~~for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	2429,~~298~~028		$	~~(474~~5,069	)	$	2334,~~824~~097		$	2739,~~858~~970		$	~~3,163~~(597	)	$	3139,~~021~~373
Unrealized gains (losses)	(24,298		)	(17,869		)	(42,167		)	(27,858		)	52,382			24,524
Unrealized losses	(29,028		)	—			(29,028		)	(39,970		)	(14,706		)	(54,676		)
Total	$	—		$	~~(18~~5,~~343~~069	)	$	~~(18~~5,~~343~~069	)	$	—		$	55(15,~~545~~303	)	$	55(15,~~545~~303	)
	Six months ended June 30,
	2013									2012
Statement of operations line item:	Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized Losses for the Current Period			Total			Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized			Realized and Unrealized Gains for the Current Period			Total
Commodity price risk management gain (loss), net
Realized gains (losses)	$	71,195		$	(13,274	)	$	57,921		$	55,504		$	14,890		$	70,394
Unrealized gains (losses)	(71,195		)	—			(71,195		)	(55,504		)	25,352			(30,152		)
Total	$	—		$	(13,274	)	$	(13,274	)	$	—		$	40,242		$	40,242

Derivative Counterparties. The Managing General Partner's derivative arrangements expose this 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 revolving 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 this 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 this Partnership's derivative instruments was not significant.

Note 6 - Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, this 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 this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheet.

During the ~~three~~six months ended ~~March~~June 3130, 2013, as a result of the Managing General Partner's periodic review, no new environmental remediation liabilities were identified and this Partnership's expense for environmental remediation efforts was not significant. ~~Environmental~~This ~~remediation~~Partnership's ~~liabilities~~environmental ~~for~~remediation ~~this~~effort ~~Partnership~~liabilities as of ~~March~~ June 3130, 2013 and December 31, 2012 were not significant.

The Managing General Partner is not currently aware of any environmental claims existing as of March 31, 2013 which have not been provided for or would otherwise have a material impact on this 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 this Partnership's properties.~~ 9-

-PDC 102002-C LIMITED PARTNERSHIP

PDC 2002-C Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2013

(unaudited)

The Managing General Partner is not currently aware of any environmental claims existing as of June 30, 2013 which have not been provided for or would otherwise have a material impact on this 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 this Partnership's properties.

Royalty Matters

During the three months ended June 30, 2013, this Partnership recognized charges totaling approximately $32,000 related to royalty payment disputes with interest owners in the Piceance Basin. This charge was included in Direct costs - general and administrative expenses within discontinued operations. The settlement charge was allocated to this Partnership based upon historical revenue amounts. The payment was made by the Managing General Partner as of June 30, 2013, and is included as a liability in the Due to Managing General Partner-other, net on the balance sheet.

Note 7 - Asset Retirement Obligations

The following table presents the changes in carrying amounts of the asset retirement obligations associated with this Partnership's working interest in ~~natural~~crude ~~gas~~oil and ~~crude~~natural ~~oil~~gas properties:

	Three months ended
	Amount
	March 31, 2013
Balance at December 31, 2012	$	236,768
Beginning balance	$	236,768
Accretion expense	8,035
Accretion expense	4,082
Obligations discharged with disposal of properties	(40,275		)
Ending balance	240,850
Balance at June 30, 2013	$	204,528
Liabilities held for sale (1)	(39,869		)
Long-term portion	$	200,981

~~(1)~~- Represents asset retirement obligations related to this Partnership's assets held for sale. See Note 8, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned sale of these properties.10-

~~Note~~PDC 8 2002-C ~~Assets~~LIMITED ~~Held for Sale, Divestitures and Discontinued Operations~~PARTNERSHIP

Piceance Basin. On February 4, 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement ("PSA") with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets for cash consideration of approximately $434,000, subject to post-closing adjustments. Under the same PSA, PDC has agreed to sell to Caerus PDC's and PDC sponsored partnerships' Piceance Basin assets and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Based on the amounts allocated to this Partnership in the PSA, PDC determined that it was in the best interest of this Partnership to sell its Piceance Basis assets under the PSA. The PSA does not include any of this Partnership's Wattenberg Field assets. These assets have been classified as held for sale in the unaudited condensed balance sheet as of March 31, 2013. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence and with respect to natural gas derivative position settlements that will be assumed by Caerus. The Managing General Partner intends to use the proceeds from the asset disposal for operational needs, for additional reserve development of natural gas, NGLs and crude oil production in the Wattenberg Field (the "Additional Development Plan") or distributions to Partners. There can be no assurance this Partnership will be successful in closing such divestiture. Following the planned sale, this Partnership will not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the unaudited condensed statement of operations for all periods presented.

Selected financial information related to divested and discontinued operations. The tables below set forth selected financial information related to this Partnership's Piceance Basin net assets held for sale and operating results related to discontinued operations. Net assets held for sale represents this Partnership's Piceance Basin assets that are expected to be sold, net of liabilities that are expected to be assumed by Caerus. While the reclassification of revenues and expenses related to discontinued operations for the 2012 period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.

- 11-

PDC 2002-C Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 2013

(unaudited)

~~The~~Note ~~following~~8 ~~table~~- ~~presents~~Divestitures ~~balance~~and ~~sheet~~Discontinued ~~data~~Operations ~~related to assets held for sale:~~

	As of
	March 31, 2013
	Net Assets
Balance Sheet	Held for Sale
Assets
Properties, successful efforts method, at cost	$	214,368
Accumulated depreciation, depletion and amortization	(149,583		)
Total assets	64,785
Liabilities
Asset retirement obligations	39,869
Net Assets	$	24,916

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement ("PSA") with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. Under the same PSA, PDC agreed to sell to Caerus the Piceance Basin assets of PDC and certain other PDC-sponsored partnerships and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $400,000, subject to customary post-closing adjustments. The sale resulted in a gain on divestiture of assets of approximately $347,000. The Managing General Partner distributed a portion of the proceeds from the asset divestiture for distributions to its Partners in July 2013. See Note 9, Subsequent Events, for additional information regarding the use of proceeds received from the Piceance Basin asset sale.

~~The~~Following ~~following~~the ~~table~~sale, ~~presents~~this ~~statements~~Partnership ofdoes not have a significant continuing involvement in the operations ~~data~~of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to ~~this~~these ~~Partnership's~~assets have been separately reported as discontinued operations: in the unaudited condensed statement of operations for all periods presented.

	Three Months Ended March 31,
Statement of Operations - Discontinued Operations	2013		2012
Revenues:
Natural gas, NGLs and crude oil sales	$	24,408	$	17,156
Total revenues	24,408		17,156
Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	17,420		11,793
Depreciation, depletion and amortization	3,380		2,857
Accretion of asset retirement obligations	600		565
Total operating costs and expenses	21,400		15,215
Income from discontinued operations	$	3,008	$	1,941

The following table presents statement of operations data related to this Partnership's discontinued operations for the Piceance Basin divestiture:

- 12-



	Three Months Ended June 30,						Six Months Ended June 30,
Statement of Operations - Discontinued Operations	2013			2012			2013			2012

Revenues:
Crude oil, natural gas and NGLs sales	$	25,180		$	11,046		$	49,588		$	28,202

Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	11,592			9,252			29,012			21,045
Depreciation, depletion and amortization	—			2,732			3,380			5,589
Direct costs - general and administrative expense	31,840			—			31,840			—
Accretion of asset retirement obligations	405			573			1,005			1,138
Gain on sale of crude oil and natural gas properties	(347,493		)	—			(347,493		)	—
Total operating costs and expenses	(303,656		)	12,557			(282,256		)	27,772

Income (loss) from discontinued operations	$	328,836		$	(1,511	)	$	331,844		$	430

While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.

Note 9 - Subsequent Events

In July 2013, this Partnership distributed a portion of the proceeds in the amount of $220,000 received for the Piceance Basin asset divestiture to the Partners as follows:




	Amount

Managing General Partner	$	44,000
Investor Partners	176,000
Total	$	220,000

- 11-

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~~crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude oil~~NGLs. This Partnership began ~~natural~~crude ~~gas~~oil and ~~crude~~natural ~~oil~~gas operations in November 2002 and operates 1412 gross (1210.7 net) productive wells located in the ~~Rocky~~Wattenberg ~~Mountain~~Field ~~Region~~ of Colorado. The Managing General Partner markets this Partnership's ~~natural~~crude ~~gas~~oil and ~~crude~~natural ~~oil~~gas production to midstream marketers. ~~Natural~~Crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude~~NGLs ~~oil~~are is sold primarily under market-sensitive contracts in which the price varies as a result of market forces. PDC does not charge a separate fee for the marketing of the ~~natural~~crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude~~NGLs ~~oil~~ because these services are covered by the monthly well operating charge. PDC, on behalf of this Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts and/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, costs incurred and availability of PDC or third-party owned pipeline capacity, and other factors such as high pressures in the gathering system whether caused by heat or third-party facilities issues, may impact this 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 Partners' average annual rate of return being less than 12.8% in June 2011, this Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution. This modified distribution ~~will~~ended ~~end~~ in April 2013. See Note 1, General and Basis of Presentation, to the unaudited 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

~~Planned~~Crude ~~Natural~~Oil ~~Gas~~ and ~~Crude~~Natural ~~Oil~~Gas Properties ~~Divestitures~~Divestiture

OnIn February 4, 2013, this Partnership's Managing General Partner entered into a ~~PSA~~purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC ("Caerus"), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin ~~oil~~assets and ~~gas~~certain ~~properties for cash consideration of approximately $434,000~~derivatives. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence and with respect to natural gas derivative positions that will be assumed by Caerus. Under the same PSA, PDC ~~has~~ agreed to sell to Caerus the Piceance Basin assets of PDC's and ~~PDC~~certain other PDC-sponsored partnerships' ~~Piceance Basin assets~~ and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. ~~Based~~In onJune ~~the~~2013, ~~amounts allocated to~~ this ~~Partnership~~divestiture ~~in the PSA, PDC determined that it~~ was incompleted ~~the~~with ~~best~~total ~~interest~~consideration ofto this Partnership toof ~~sell~~approximately ~~its~~$400,000, ~~Piceance~~subject ~~Basis~~to ~~assets~~customary ~~under~~post-closing ~~the PSA~~adjustments. The ~~PSA~~sale ~~does~~resulted ~~not~~in ~~include~~a ~~any~~gain ofon ~~this~~divestiture ~~Partnership's~~of ~~Wattenberg~~assets ~~Field~~of ~~assets~~approximately $347,000. The effective date of ~~the~~this transaction iswas January 1, 2013. ~~The~~Following ~~Managing General Partner intends to use~~ the ~~proceeds from the~~ sale ~~for~~to Caerus, this Partnership's ~~operational~~does ~~needs,~~not ~~for~~have ~~the~~continuing ~~Additional~~involvement ~~Development~~in ~~Plan~~the oroperations ~~distributions to Partners. As~~ of ~~December 31~~, ~~2012,~~or ~~total~~cash ~~estimated~~flows ~~proved~~from, ~~reserves~~the ~~related~~Piceance toBasin ~~these~~oil ~~assets~~and ~~were~~gas 27properties. ~~MMcf of natural gas~~Accordingly, orthe 5results ~~MBbl~~ of ~~crude~~operations ~~oil~~related ~~equivalent.~~to ~~See~~these ~~Note~~assets 8,have ~~Assets~~been ~~Held~~separately ~~for~~reported ~~Sale,~~as ~~Divestitures~~discontinued ~~and~~operations ~~Discontinued~~in ~~Operations,~~the ~~to this Partnership's~~ unaudited condensed ~~financial~~statement ~~statements~~of ~~included~~operations ~~elsewhere in this report~~ for ~~additional~~all ~~details~~periods ~~related~~presented. toIn ~~the~~July ~~planned~~2013, ~~divestiture of~~ this Partnership's ~~Piceance~~distributed ~~assets.~~a ~~There~~portion ~~can~~of bethe noproceeds ~~assurance~~of ~~that~~the ~~this~~sale ~~transaction~~to ~~will~~its ~~close~~Partners ason ~~planned.~~a Inpro ~~addition,~~rata ~~purchase price adjustments may reduce this Partnership's proceeds from the transaction~~basis.

Partnership Operating Results Overview

~~Natural~~Crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude~~NGLs ~~oil~~ sales from continuing operations decreased 2642%, or approximately $2380,000, for the first ~~three~~six months of 2013 compared to the first ~~three~~six months of 2012, while sales volumes from continuing operations ~~decreased~~declined 2739% period-to-period. ~~Partially~~The ~~offsetting this decrease, the~~ average sales price per barrel of crude oil equivalent ("Boe"), excluding the impact of realized derivative gains, was $5048.9001 for the current period compared to $5051.2827 for the same period a year ago. Realized gains from all natural gas derivatives, including net gains from the sale of this Partnership's remaining derivative positions in late June, contributed approximately $2458,000 to total revenues for the first ~~three~~six months of 2013 compared to approximately $3170,000 from natural gas derivatives for the first ~~three~~six months of 2012.

- 1312-

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 this Partnership’s results from continuing operations:

	Three months ended March 31,
	Three months ended June 30,							Six months ended June 30,
	2013		2012			Change		2013		2012		Change
Number of gross producing wells (end of period)	1211		1211			—		11		11		—
Production(1)
Natural gas (Mcf)	3,084		4,271			(28	)%
Crude oil (Bbl)	290		967			(70	)%	812		1,616		(50	)%
NGLs (Bbl)	246		385			(36	)%
Natural gas (Mcf)	2,804		4,195			(33	)%	5,888		8,466		(30	)%
Crude oil (Bbl)	522		649			(20	)%
NGLs (Bbl)	210		250			(16	)%	456		635		(28	)%
Crude oil equivalent (Boe)(2)	~~1,282~~967		1,~~746~~916			(2750	)%	2,249		3,662		(39	)%
Average Boe per day	1411		1921			(2750	)%	12		20		(39	)%
Natural gas, NGLs and crude oil sales
Crude oil, natural gas and NGLs sales
Natural gas	$	9,070	$	11,222		(19	)%
Crude oil	$	25,040	$	79,476		(68	)%	$	70,406	$	140,523	(50	)%
NGLs	10,821		15,525			(30	)%
Natural gas	10,248		7,683			33	%	19,318		18,905		2	%
Crude oil	45,366		61,047			(26	)%
NGLs	7,434		12,794			(42	)%	18,255		28,319		(36	)%
Total natural gas, NGLs and crude oil sales	$	65,257	$	87,794		(26	)%
Total crude oil, natural gas and NGLs sales	$	42,722	$	99,953		(57	)%	$	107,979	$	187,747	(42	)%
Realized gain on derivatives, net
Natural gas	$	2334,~~824~~097	$	3139,~~021~~373		(2313	)%	$	57,921	$	70,394	(18	)%
Total realized gain on derivatives, net	$	2334,~~824~~097	$	3139,~~021~~373		(2313	)%	$	57,921	$	70,394	(18	)%
Average selling price (excluding realized gain on derivatives)
Natural gas (Mcf)	$	2.94	$	2.63		12	%
Crude oil (per Bbl)	$	86.34	$	82.19		5	%	$	86.71	$	86.96	*
NGLs (Bbl)	43.99		40.32			9	%
Natural gas (Mcf)	3.65		1.83			99	%	3.28		2.23		47	%
Crude oil (per Bbl)	86.91		94.06			(8	)%
NGLs (Bbl)	35.40		51.18			(31	)%	40.03		44.60		(10	)%
Crude oil equivalent (per Boe)	5044.9018		5052.2817			1(15	)%	48.01		51.27		(6	)%
Average cost per Boe
Natural gas, NGLs and crude oil production cost(3)	$	17.29	$	38.74		(55	)%
Crude oil, natural gas and NGLs production cost(3)	$	51.43	$	(25.42	)	*		$	31.97	$	5.17	*
Depreciation, depletion and amortization	32.76		24.9697			31	%	32.76		24.96		31	%
Operating costs and expenses
Direct costs - general and administrative	$	3032,~~863~~600	$	2931,~~060~~038		65	%	$	63,463	$	60,098	6	%
Depreciation, depletion and amortization	4231,~~003~~682		4347,~~580~~840			(434	)%	73,685		91,420		(19	)%
Cash distributions	$	3915,~~464~~598	$	7,~~139~~626		*105	%	$	55,062	$	14,765	*

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

Amounts may not recalculate due to rounding.

_______________

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

⁽²⁾ One Bbl of crude oil or NGL equals six Mcf of natural gas.

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

- 1413-

Index

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

(A West Virginia Limited Partnership)

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.

Boe - Barrels of crude oil equivalent.

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~~Crude -Oil, ~~One~~Natural ~~million~~Gas ~~cubic~~and ~~feet~~NGLs ~~of natural gas equivalent.~~ Sales

Crude Oil, Natural Gas and NGLs Pricing. This Partnership's results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and the Managing General Partner's ability to market this Partnership's production effectively. Crude ~~Oil~~oil, ~~Sales~~natural gas and NGLs prices are among the most volatile of all commodity prices. These price variations can have a material impact on this Partnership's financial results and capital expenditures.

~~Natural~~Crude ~~Gas,~~oil ~~NGLs~~pricing ~~and~~is ~~Crude~~predominately ~~Oil~~driven ~~Pricing.~~by ~~This~~the ~~Partnership's~~physical ~~results~~market, ofsupply ~~operations~~and ~~depend~~demand, ~~upon~~the ~~many~~financial ~~factors,~~markets ~~particularly~~and ~~the~~national ~~price~~and ofinternational ~~natural~~politics. ~~gas,~~The ~~NGLs~~majority ~~and~~of this Partnership's crude oil ~~and~~is ~~the~~sold ~~Managing~~on ~~General~~a ~~Partner's~~calendar-year ~~ability~~basis toat ~~market~~a ~~this~~fixed ~~Partnership's~~differential ~~production~~to ~~effectively~~NYMEX pricing. Natural gas, ~~NGLs~~prices ~~and~~vary ~~crude~~by ~~oil~~region ~~prices~~and ~~are~~locality, ~~among~~depending upon the ~~most~~distance ~~volatile~~to markets, availability of ~~all~~pipeline ~~commodity~~capacity ~~prices~~and supply and demand relationships in that region or locality. ~~These~~The price ~~variations~~this ~~can~~Partnership ~~have~~receives afor ~~material~~its ~~impact~~natural gas produced is based on ~~this~~the Colorado Interstate Gas ("CIG") price. This Partnership's ~~financial~~NGLs ~~results~~price ~~and~~is ~~capital~~mainly ~~expenditures~~based on prices from the Conway hub in Kansas where the Wattenberg production is marketed.

Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price this Partnership receives for its natural gas produced is based on the Colorado Interstate Gas ("CIG") price. This Partnership's NGL price is mainly based on prices from the Conway hub in Kansas where the Wattenberg production is marketed. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of this Partnership's crude oil is sold on a calendar-year basis at a fixed differential to NYMEX pricing.

This Partnership currently uses the "net-back" method of accounting for these arrangements related to its natural gas sales. This Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price as transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

~~Recently,~~During athe ~~combination~~spring ofand ~~increased~~summer ~~drilling~~of ~~activity~~2012 and ~~curtailments~~the ~~due~~latter topart ~~limited~~of ~~capacity~~the onsecond ~~local~~quarter ~~gathering~~of 2013 and, ~~processing~~to ~~infrastructure~~a ~~and~~lesser extent, in some other recent periods, ~~higher~~this ~~temperatures,~~Partnership's Wattenberg Field production has ~~resulted~~been inadversely ~~capacity~~impacted ~~constraints~~by inincreasing line pressures on the ~~Wattenberg~~gathering ~~Field~~system operated by this Partnership's third-party service provider. The ~~Managing~~continued ~~General~~acceleration ~~Partner~~of ~~anticipates~~industry ~~that~~drilling ~~this~~activity, ~~Partnership~~combined ~~will~~with ~~again~~higher ~~experience~~temperatures ~~high~~in ~~line~~some ~~pressures~~periods, have resulted in ~~2013,~~reduced ~~particularly~~system compressor efficiency and increased line pressures in the ~~summer~~Wattenberg ~~months,~~Field. asThe ~~field-wide~~curtailments ~~production~~that ~~volumes~~have ~~from~~occurred ~~the~~to ~~ongoing~~date ~~development~~in of2013 are consistent with what the ~~successful~~Managing ~~horizontal~~General ~~Wattenberg~~Partner ~~play~~expected ~~outpace~~to ~~current~~occur ~~midstream~~during ~~capacity~~this period. The Managing General Partner is working closely with the primary midstream provider in the Wattenberg Field who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity. Initial system improvements have already been implemented with the startup of a new field compressor station, as well as installation and commissioning of gas bypass facilities at two gas processing plants in May and June of 2013. These projects increased midstream system capacity and have helped to mitigate the impact of increased production volumes on system pressures. The Managing General Partner expects reduced line pressures to substantially benefit this Partnership in late 2013, concurrent with the startup of the LaSalle gas plant and associated field compressor stations. Like most producers, this Partnership relies on its third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with production growth. As a result, the timing and availability of these facilities is beyond this Partnership's or the Managing General Partner's control.

- 1514-

Index

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

(A West Virginia Limited Partnership)

~~Three~~Six months ended ~~March~~June 3130, 2013 as compared to ~~three~~six months ended ~~March~~June 3130, 2012

For the ~~three~~six months ended ~~March~~June 3130, 2013 compared to the same period in 2012, ~~natural~~crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude~~NGLs ~~oil~~ production from continuing operations, on an energy equivalency-basis, decreased 2739%, primarily due to normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field.

The ~~approximately~~approximate $2380,000, or 2642%, decrease in sales from continuing operations for the 2013 ~~three~~six month period as compared to the prior year period was a reflection of sales volume decreases of 2739% ~~partially offset by an increase in the average sales price of 1%~~. The average sales price per Boe, excluding the impact of realized derivative gains, was $5048.9001 for the current year ~~three~~six month period compared to $5051.2827 for the same period a year ago.

~~Natural~~Crude ~~gas,~~oil ~~NGLs~~ and ~~crude~~NGLs ~~oil~~ sales from continuing operations for the ~~three~~six months ended ~~March~~June 3130, 2013 decreased by 1950%~~, 30%~~ and 2636%, respectively, partially offset by increased natural gas sales of 2% as compared to the ~~three~~six months ended ~~March~~June 3130, 2012. The ~~decrease~~crude inoil ~~natural gas~~ sales ~~resulted~~decrease ~~from~~was ~~lower~~due ~~natural~~primarily ~~gas~~to ~~production~~a ~~volumes~~sales ofvolume ~~28%,~~decrease ~~partially offset by increased prices per Mcf~~ of 1250%. The decrease in NGLs sales was due to a decrease of 3628% in NGLs production volumes, ~~partially~~and ~~offset~~ by ana ~~increase~~decrease in the average commodity price per Bbl of 910%. The ~~crude~~increase ~~oil~~in ~~sales~~natural ~~decrease~~gas ~~was~~sales ~~due~~resulted tofrom aincreased ~~production~~prices ~~volume~~per ~~decrease~~Mcf of 2047%, ~~and~~partially aoffset ~~decrease~~by inlower ~~the~~natural ~~average~~gas ~~commodity~~production ~~price~~volumes ~~per Bbl~~ of 830%.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

For the three months ended June 30, 2013 compared to the same period in 2012, crude oil, natural gas and NGLs production from continuing operations, on an energy equivalency-basis, decreased 50%, primarily due to normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field.

The approximate $57,000, or 57%, decrease in sales from continuing operations for the 2013 three month period as compared to the prior year period was a reflection of sales volume decreases of 50% and a decline in the average sales price of 15%. The average sales price per Boe, excluding the impact of realized derivative gains, was $44.18 for the current year three month period compared to $52.17 for the same period a year ago.

Crude oil and NGLs sales from continuing operations for the three months ended June 30, 2013 decreased by 68% and 42%, respectively, partially offset by increased natural gas sales of 33% as compared to the three months ended June 30, 2012. The decrease in crude oil sales was due primarily to a sales volume decrease of 70%, partially offset by an increase in the average commodity price per Bbl of 5%. The decrease in NGLs sales was due to a 16% decrease in NGLs production volumes and a decrease in the average commodity price per Bbl of 31%. The increase in natural gas sales resulted from increased prices per Mcf of 99%, partially offset by lower natural gas production volumes of 33%.

Commodity Price Risk Management

This Partnership ~~uses~~used various derivative instruments to manage fluctuations in natural gas prices. ~~This~~In ~~Partnership~~late ~~has~~June, inderivative ~~place~~instruments ~~collars,~~that ~~fixed-price~~were ~~swaps~~due ~~and/or~~to ~~basis~~mature ~~swaps~~subsequent onto aJune 30, ~~portion~~2013 ofwere ~~this~~liquidated, ~~Partnership's~~which ~~estimated~~resulted ~~natural~~in ~~gas~~an ~~production.~~approximate ~~This~~$17,000 ~~Partnership~~net ~~sells~~realized ~~its~~gain. Realized gains on natural gas, atexclusive ~~similar~~of ~~prices~~basis toswaps, ~~the~~of ~~indices~~approximately ~~inherent~~$34,000 inwere ~~this~~offset ~~Partnership's~~by ~~derivative~~realized ~~instruments.~~losses Asof aapproximately ~~result~~$17,000 ~~for~~on ~~the volumes underlying~~ this Partnership's ~~derivative~~basis swap positions. As of June 30, 2013, this Partnership ~~ultimately~~did ~~realizes~~not ahave ~~price~~any ~~related~~derivative toinstruments ~~its~~in ~~collars~~place offor noits ~~less~~future ~~than~~production. Currently, the ~~floor~~Managing ~~and~~General noPartner ~~more~~does ~~than~~not ~~the~~anticipate ~~ceiling~~entering ~~and,~~into ~~for~~derivative ~~this~~instruments ~~Partnership's~~for ~~commodity~~any ~~swaps,~~of this Partnership's ~~ultimately~~future ~~realizes the fixed price related to its swaps~~production.

This Partnership had in place collars, fixed-price swaps and/or basis swaps on a portion of this Partnership's estimated natural gas production. This Partnership sold its natural gas at similar prices to the indices inherent in this Partnership's derivative instruments. As a result, for the volumes underlying this Partnership's derivative positions, this Partnership ultimately realized a price related to its collars of no less than the floor and no more than the ceiling and, for this Partnership's commodity swaps, this Partnership ultimately realized the fixed price related to its swaps.

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

- 15-

Index

PDC 2002-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

	Three months ended March 31,
	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Commodity price risk management gain (loss), net:
Realized gains
Natural gas	$	2334,~~824~~097		$	3139,~~021~~373		$	57,921		$	70,394
Total realized gains, net	2334,~~824~~097			3139,~~021~~373			57,921			70,394
Unrealized gains (losses)
Reclassification of realized gains included in
prior periods unrealized gains	(2429,~~298~~028		)	(2739,~~858~~970		)	(71,195		)	(55,504		)
Unrealized gains (losses) for the period	~~(17,869~~—		)	52(14,~~382~~706		)	—			25,352
Total unrealized gains (losses), net	(42,167		)	24,524
Total unrealized losses, net	(29,028		)	(54,676		)	(71,195		)	(30,152		)
Total commodity price risk management gain (loss), net	$	~~(18~~5,~~343~~069	)	$	55(15,~~545~~303	)	$	(13,274	)	$	40,242

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

Realized gains of approximately $58,000 recognized in the six months ended June 30, 2013 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the six months ended June 30, 2013, realized gains on natural gas, exclusive of basis swaps, were approximately $114,000. These gains were offset in part by realized losses of approximately $56,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

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 this 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 this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this 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 this 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 this Partnership's natural gas positions were approximately $29,000, offset by unrealized losses on this Partnership's CIG basis swaps of approximately $4,000.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

Realized gains of $34,000 recognized in the three months ended June 30, 2013 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the three months ended June 30, 2013, realized gains on natural gas, exclusive of basis swaps, were $69,000. These gains were offset in part by realized losses of $35,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

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 this 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 this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this 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 this Partnership's open positions and by the narrowing of the CIG basis forward curve. For the period ended June 30, 2012, unrealized losses on this Partnership's natural gas positions were approximately $12,000 in addition to unrealized losses on this Partnership's CIG basis swaps of approximately $3,000.

- 16-

Index

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

(A West Virginia Limited Partnership)

~~Three~~Crude ~~months ended March 31~~Oil, ~~2013~~Natural asGas ~~compared~~and toNGLs ~~three~~Production ~~months ended March 31, 2012~~ Costs

~~Realized~~Generally, ~~gains~~crude ofoil, ~~approximately~~natural ~~$24,000~~gas ~~recognized~~and inNGLs ~~the~~production ~~three~~costs ~~months~~vary ~~ended~~with ~~March~~changes 31in total crude oil, ~~2013~~natural ~~were~~gas ~~primarily~~and NGLs sales and production volumes. Production taxes are estimates by the ~~result~~Managing ofGeneral ~~lower~~Partner ~~natural~~based ~~gas~~on ~~spot~~tax ~~prices~~rates atdetermined ~~settlement~~using ~~compared~~published information. These estimates are subject to ~~the~~revision ~~respective~~based ~~strike~~on ~~price~~actual ofamounts ~~this~~determined ~~Partnership's~~during ~~natural~~future ~~gas~~filings ~~derivative~~by ~~positions.~~the ~~For~~Managing General Partner with the ~~three~~taxing ~~months~~authorities. ~~ended~~Production ~~March~~taxes ~~31,~~vary ~~2013~~directly with total crude oil, ~~realized~~natural ~~gains~~gas onand NGLs sales. Transportation costs vary directly with natural gas, ~~exclusive~~production ofvolumes. Fixed monthly well operating costs increase on a per unit basis ~~swaps,~~as ~~were~~production ~~approximately~~decreases ~~$44,000~~per the historical decline curve. ~~These~~In ~~gains~~addition, ~~were~~general ~~offset~~oil infield ~~part~~services byand ~~realized~~all ~~losses~~other ofcosts ~~approximately~~vary ~~$20,000~~and can fluctuate based on ~~this~~services ~~Partnership's~~required, ~~basis~~but ~~swap~~are ~~positions~~expected to increase as ~~the~~wells ~~negative~~age ~~basis~~and ~~differential~~require ~~between~~more ~~NYMEX~~extensive repair and ~~CIG~~maintenance. ~~weighted-average~~These ~~price~~costs ~~was~~include ~~narrower~~water ~~than~~hauling ~~the~~and ~~strike~~disposal, ~~price~~equipment ofrepairs ~~this~~and ~~Partnership's~~maintenance, ~~basis~~snow ~~swaps.~~removal, environmental compliance and remediation and service rig workovers.

~~Unrealized~~Six ~~losses~~months ~~of approximately $18,000 for the quarter~~ ended ~~March 31~~June 30, 2013 ~~were~~as ~~primarily~~compared ~~related~~ to ~~the~~six ~~upward~~months ~~shift~~ended inJune 30, ~~the~~2012 ~~natural gas forward curve and its impact on the fair value of this Partnership's open positions.~~

~~Realized~~Crude ~~gains~~oil, ofnatural ~~approximately~~gas ~~$31,000~~and ~~recognized~~NGLs inproduction costs for the ~~three~~six months ended ~~March~~June 3130, ~~2012~~2013 ~~were~~increased approximately $53,000 compared to the same period in 2012, primarily because the ~~result~~2012 ofcrude ~~lower~~oil, natural gas ~~spot~~and ~~prices~~NGLs atproduction ~~settlement~~costs ~~compared~~included toan ~~the~~$89,000 ~~respective~~reduction ~~strike~~in ~~price~~environmental ofremediation ~~this~~liabilities. ~~Partnership's~~The ~~natural~~reduction ~~gas~~in ~~derivative~~environmental ~~positions. For~~remediation ~~the~~liabilities ~~three~~in ~~months~~June ~~ended~~2012 ~~March~~was ~~31,~~to ~~2012,~~reverse ~~realized~~the ~~gains~~accrual onas ~~natural~~it ~~gas~~was determined that the liabilities, ~~exclusive~~recognized ofin ~~basis~~June ~~swaps~~2011, were ~~approximately~~completed ~~$54,000~~for significantly less cost than anticipated. ~~These~~The ~~gains~~environmental ~~were~~remediation ~~offset~~liability reversal in ~~part~~2012 byreduced ~~realized~~production ~~losses~~and ofoperating ~~approximately~~costs ~~$23,000~~per onBoe ~~this~~by ~~Partnership's~~$24.30 ~~basis~~for ~~swap~~the ~~positions~~six asmonths ~~the~~ended ~~negative~~June ~~basis~~30, ~~differential~~2012. ~~between~~The ~~NYMEX~~year-over-year ~~and~~decrease ~~CIG~~was ~~weighted~~also ~~average~~due ~~price~~to ~~was~~lower ~~narrower~~lease ~~than~~operating ~~the~~costs ~~strike~~in ~~price~~2013 ofas ~~this~~workover ~~Partnership's~~activities ~~basis~~were ~~swaps~~lower in 2012.

~~Unrealized~~Three ~~gains~~months ofended ~~approximately $52~~June 30,~~000~~ ~~for~~2013 ~~the~~as compared to three months ended ~~March 31~~June 30, 2012 ~~were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions.~~

~~The~~Crude ~~following~~oil, ~~table~~natural ~~presents~~gas ~~this~~and ~~Partnership's~~NGLs ~~derivative~~production ~~positions~~costs infor ~~effect~~the asthree ofmonths ~~March~~ended June 3130, 2013: increased approximately $98,000 compared to the same period in 2012, primarily because the 2012 crude oil, natural gas and NGLs production costs included an $89,000 reduction in environmental remediation liabilities. 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 Boe by $46.45 for the three months ended June 30, 2012.

	Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/Index	Quantity(Gas-MMBtu(1))	Weighted-AverageContractPrice		Quantity(Gas-MMBtu(1))	Weighted-AverageContractPrice			Fair Value atMarch 31, 2013
Natural Gas
NYMEX
04/01 - 06/30/2013	11,706	$	7.12	11,706	$	(1.88	)	$	17,535
07/01 - 09/30/2013	11,620	7.12		11,620	(1.88		)	16,107
10/01 - 12/31/2013	11,388	7.12		11,388	(1.88		)	14,342
Total(2)	34,714			34,714				$	47,984

Depreciation, Depletion and Amortization

~~(1)~~Six Amonths ~~standard~~ended ~~unit~~June 30, of2013 ~~measure~~as ~~for~~compared ~~natural~~to ~~gas~~six ~~(one~~months ~~MMBtu~~ended ~~equals~~June 30, ~~one~~2012 ~~Mcf).~~

Depreciation, depletion and amortization (2"DD&A") ~~Pursuant~~expense related to acrude ~~purchase~~oil and ~~sale~~natural ~~agreement~~gas ~~entered~~properties ~~into~~is ondirectly ~~February~~related 4,to ~~2013,~~proved ~~approximately~~reserves ~~19,773~~and ~~MMBtu~~production ofvolumes. ~~the~~DD&A ~~above~~expense ~~Fixed-Price~~for ~~Swaps,~~continuing ~~and~~operations andecreased ~~equal~~approximately ~~amount~~$18,000 offor ~~CIG~~the ~~Basis~~six ~~Protection~~months ~~Swaps~~ended June 30, is2013 ~~expected~~compared to bethe ~~assigned~~six tomonths ~~certain~~ended ~~affiliates~~June of30, ~~Caerus~~2012 ~~upon~~due ~~the~~to ~~closing~~lower ofproduction ~~the~~volumes, ~~planned~~offset ~~sale.~~in ~~There~~part ~~can~~by bean noincreased ~~assurance~~DD&A ~~that~~expense ~~this~~rate ~~transaction~~in ~~will~~2013. ~~close~~The asDD&A ~~planned.~~expense ~~See~~rate ~~Note~~per 8,Boe ~~Assets~~increased ~~held~~to $32.76 for ~~Sale,~~the ~~Divestiture~~2013 ~~and~~six ~~Discontinued~~months ~~Operations,~~compared to ~~this~~$24.96 ~~Partnership's~~during ~~financial~~the ~~statements~~same ~~included~~period ~~elsewhere~~ in ~~this~~2012 ~~report~~due ~~for~~to ~~additional~~the ~~information~~effect ~~regarding~~of the ~~planned~~net ~~divestiture~~downward ofrevision ~~certain~~in of this Partnership'’s ~~natural~~proved ~~gas~~developed ~~properties~~producing reserves as of December 31, 2012.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

DD&A expense for continuing operations decreased approximately $16,000 for the three months ended June 30, 2013 compared to the three months ended June 30, 2012 due to lower production volumes partially offset by an increased DD&A expense rate in 2013. The DD&A expense rate per Boe increased to $32.76 for the 2013 three months compared to $24.97 during the same period in 2012 due to the effect of the net downward revision in this Partnership’s proved developed producing reserves as of December 31, 2012.

- 17-

Index

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

(A West Virginia Limited Partnership)

Natural Gas, NGLs and Crude Oil Production Costs

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

These costs include water hauling and disposal, equipment repairs and maintenance, snow removal, environmental compliance and remediation and service rig workovers.

Three months ended March 31, 2013 as compared to three months ended March 31, 2012

Natural gas, NGLs and crude oil production costs for the three months ended March 31, 2013 decreased approximately $45,000 compared to the same period in 2012 due primarily to lower lease operating costs in 2013 as workovers and tubing repair activities were collectively higher in 2012. The natural gas, NGLs and crude oil production costs per Boe decreased to $17.29 during 2013 from $38.74 in 2012 due to the lower costs, partially offset by lower volumes in 2013.

Depreciation, Depletion and Amortization

Three months ended March 31, 2013 as compared to three months ended March 31, 2012

Depreciation, depletion and amortization ("DD&A") expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A expense for continuing operations decreased approximately $2,000 for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 due to lower production volumes and partially offset by an increased DD&A expense rate in 2013. The DD&A expense rate per Boe increased to $32.76 for the 2013 three months compared to $24.96 during the same period in 2012 due to the effect of a decrease in estimated reserves as of December 31, 2012.

Discontinued Operations

OnIn February 4, 2013, the Managing General Partner entered into a purchase and sale agreement with Caerus, pursuant to which this Partnership agreed to sell to Caerus its Piceance Basin assets ~~for~~and ~~cash~~certain derivatives. In June 2013, this divestiture was completed with total consideration to this Partnership of approximately $~~434~~400,000, subject to customary post-closing adjustments. ~~Following~~The sale resulted in a gain on divestiture of assets of $347,000. The effective date of the ~~planned~~transaction was January 1, 2013. Following the sale to Caerus, this Partnership ~~will~~does not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin assets. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the unaudited condensed statement of operations for all periods presented. See Note 8, Divestitures and Discontinued Operations, to the accompanying unaudited condensed financial statements included elsewhere in this report for additional information regarding the sale of this Partnership's Piceance Basin assets.

~~See~~The ~~Note~~table 8,below ~~Assets~~presents ~~Held~~production ~~for~~data ~~Sale,~~related ~~Divestitures and Discontinued Operations,~~ to ~~the accompanying unaudited condensed financial statements included elsewhere in~~ this ~~report~~Partnership's ~~for~~Piceance ~~additional~~Basin ~~information~~assets ~~regarding~~that ~~the~~have ~~planned~~been ~~sale~~divested ofand ~~this~~that ~~Partnership's~~are ~~Piceance~~classified ~~Basin~~as ~~assets.~~discontinued operations:

The table below presents production data related to this Partnership's Piceance Basin assets that are planned to be divested and that are classified as discontinued operations:



	Three Months Ended June 30,		Six Months Ended June 30,
Discontinued Operations	2013	2012	2013	2012
Production
Crude oil (Bbl)	1	6	8	7
Natural gas (Mcf)	7,050	9,339	15,318	19,140
Crude oil equivalent (Boe)	1,176	1,563	2,561	3,197

	Three Months Ended March 31,
Discontinued Operations	2013	2012
Production
Natural gas (Mcf)	8,268	9,801
Crude oil (Bbl)	8	2
Crude oil equivalent (Boe)	1,386	1,636

Financial Condition, Liquidity and Capital Resources

This Partnership's primary source of liquidity has been cash flows from operating activities. This source of cash has been primarily used to fund this Partnership's operating costs, direct costs-general and administrative and monthly distributions to the Investor Partners and the Managing General Partner. For the six months ended June 30, 2013, in addition to the $106,000 net cash flows from operating activities, this Partnership's liquidity was enhanced by the gross proceeds received from the sale of the Piceance Basin assets of approximately $400,000.

Fluctuations in this Partnership's operating cash flows are substantially driven by changes in commodity prices, sales volumes and, historically, realized gains and losses from commodity contracts. Commodity prices have historically been volatile and, through June 30, 2013, the Managing General Partner attempted to manage this volatility through the use of derivatives. Therefore, historically, the primary source of cash flows from operations became the net activity between crude oil, natural gas and NGLs sales and realized natural gas derivative gains and losses. This Partnership has no crude oil, natural gas or NGLs derivative positions at June 30, 2013 as all open positions were either sold to Caerus pursuant to the Piceance Basin asset divestiture or liquidated during the three months ended June 30, 2013. 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 this Partnership's revenues through June 30, 2013.

This Partnership's future operations are expected to be conducted with available funds and revenues generated from crude oil, natural gas and NGLs production activities. Crude oil, natural gas and NGLs production from existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, this Partnership anticipates a lower annual level of crude oil, natural gas and NGLs production and, in the absence of significant price increases or additional reserve development, lower revenues. This 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 adverse impact on this Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2013 and beyond, and may substantially reduce or restrict this Partnership's ability to participate in Additional Development Plan activities.

- 18-

Index

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

(A West Virginia Limited Partnership)

Financial Condition, Liquidity and Capital Resources

This Partnership's primary sources of cash for the three month periods ended March 31, 2013 and 2012 were operating activities, which include the sale of natural gas, NGLs and crude oil production, and to the net realized gains from this Partnership's derivative positions. These sources of cash were primarily used to fund this Partnership's operating costs, direct costs-general and administrative and monthly distributions to the Investor Partners and the Managing General Partner.

Fluctuations in this Partnership's operating cash flows are substantially driven by changes in commodity prices, sales volumes, which can be impacted by high line pressures, and realized gains and losses from commodity 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 cash flows from operations becomes the net activity between natural gas, NGLs and crude oil sales and realized natural gas derivative gains and losses. This Partnership does not engage in speculative positions, nor does this Partnership hold derivative instruments for 100% of this Partnership's expected future production from producing wells, and therefore may still experience significant fluctuations in cash flows from operations. As of March 31, 2013, this Partnership had natural gas derivative positions in place covering all of its expected natural gas production for the remainder of 2013 at an average price of $5.24 per Mcf. This Partnership has no NGLs 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 this Partnership's revenues.

This 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 existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, this 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. This 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 adverse impact on this Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2013 and beyond, and may substantially reduce or restrict this Partnership's ability to participate in Additional Development Plan activities.

Working Capital

At ~~March~~June 3130, 2013, this Partnership had a working capital ~~surplus~~ of approximately $80380,000, compared to a working capital ~~surplus~~ of approximately $120,000 at December 31, 2012. The ~~decrease~~increase of approximately $40260,000 was primarily due to the following changes:

• cash and cash equivalents increased, primarily due to the sale of the Piceance Basin assets to Caerus, by approximately $80451,000 between ~~March~~June 3130, 2013 and December 31, 2012;

• accounts receivable decreased by approximately $1126,000 between ~~March~~June 3130, 2013 and December 31, 2012;

• realized and unrealized derivative gains receivable decreased by approximately $4092,000 between ~~March~~June 3130, 2013 and December 31, 2012; ~~and~~

• ~~amounts due to Managing General Partner-other, net, excluding natural gas, NGLs and crude~~ oil ~~sales~~inventory ~~received~~decreased ~~from third parties and realized derivative gains, increased~~ by approximately $695,000 between ~~March~~June 3130, 2013 and December 31, 2012.;

~~Additional~~• ~~Development~~accounts ~~Plan~~payable ~~activities, which would include investments in equipment~~ and ~~services~~accrued toexpenses ~~complete~~increased ~~refracturing~~by ~~and~~approximately ~~recompletion opportunities~~$12,000 ~~are~~between ~~suspended~~June ~~until pipeline capacity improves. If the Additional Development Plan commences~~30, ~~funding~~2013 ~~will be provided by the withholding of distributable cash flows from the Managing General Partner~~ and ~~Investor~~December ~~Partners.~~31, ~~Future~~2012; ~~working capital balances are expected to fluctuate by increasing during periods of Additional Development Plan funding~~ and ~~decreasing during periods when payments are made for refracturing or recompletion activities.~~

-• 19amounts due to Managing General Partner-other, net, excluding crude oil, natural gas and NGLs sales received from third parties and realized derivative gains, increased by approximately $56,000 between June 30, 2013 and December 31, 2012.

~~Index~~Additional Development Plan activities have been suspended. If the Additional Development Plan commences, funding will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners. Future working capital balances are expected to fluctuate by increasing during periods of Additional Development Plan funding and decreasing during periods when payments are made for refracturing or recompletion activities.

PDC 2002-C Limited Partnership

(A West Virginia Limited Partnership)

Cash Flows

Operating Activities

This Partnership's cash flows from operating activities ~~are~~were primarily impacted by commodity prices, production volumes, realized gains and losses from derivative positions, operating costs and direct costs-general and administrative expenses. The key components for the changes in this Partnership's cash flows from operating activities are described in more detail in Results of Operations above.

Net cash flows from operating activities were ~~approximately~~ $~~119~~106,000 for the ~~three~~six months ended ~~March~~June 3130, 2013 compared to ~~approximately~~ $715,000 for the comparable period in 2012. The increase of ~~approximately~~ $~~112~~91,000 in cash from operating activities was due primarily to the following:

• a decrease in ~~natural~~crude ~~gas~~oil, ~~NGLs~~natural gas and ~~crude~~NGLs ~~oil~~ sales receipts of approximately $6343,000 ;

• an increase in commodity price risk management realized gain receipts of approximately $610,000; and

• a decrease in production costs and direct costs-general and administrative payments of approximately $~~169~~124,000.

Investing Activities

~~From~~Cash ~~time~~flows tofrom ~~time,~~investing ~~this~~activities ~~Partnership~~primarily ~~invests~~consist inof ~~equipment~~proceeds ~~which~~received ~~supports~~from ~~treatment,~~the ~~delivery~~dispositions ~~and~~of ~~measurement~~crude ofoil and natural gas properties, ~~NGLs~~offset by investments in equipment and services. During the six months ended June 30, 2013, proceeds from the dispositions of crude oil orand ~~environmental~~natural ~~protection.~~gas ~~There~~properties were noapproximately ~~investing~~$400,000. ~~activities~~From ~~for~~time ~~either~~to oftime, ~~the~~this ~~three~~Partnership ~~months~~invests ~~ended~~in ~~March~~equipment 31which supports treatment, ~~2013~~delivery and measurement of crude oil, natural gas and NGLs or ~~2012~~environmental protection.

~~Financing~~- ~~Activities~~19-

This Partnership initiated monthly cash distributions to investors in May 2003 and has distributed $9.7 million through March 31, 2013. The table below presents cash distributions to this Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to the Managing General Partner for its 20% general partner interest in this Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in this Partnership, as well as amounts distributed to the Managing General Partner for limited partnership units repurchased.

Distributions
Three months ended March 31,	Managing General Partner		Investor Partners		Total
2013	$	3,199	$	36,265	$	39,464
2012	713		6,426		7,139

Three months ended March 31, 2013 as compared to three months ended March 31, 2012

The increase in total distributions for the three months ended March 31, 2013 as compared to 2012 is primarily due to an increase in cash flows from operating activities during 2013.

Beginning in June 2011, when the Investor Partners' average annual rate of return fell below 12.8%, this 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 $4,694 and $715 for the three months ended March 31, 2013 and 2012, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02. The performance obligation allocation rate modifications will continue until April 2013, when the provision expired under the terms of the Agreement.

Off-Balance Sheet Arrangements

As of March 31, 2013, this 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 this Partnership's financial condition, results of operations, liquidity, capital expenditures or capital resources.

- 20-

Index

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

(A West Virginia Limited Partnership)

Financing Activities

This Partnership initiated monthly cash distributions to investors in May 2003 and has distributed $9.7 million through June 30, 2013. The table below presents cash distributions to this Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to the Managing General Partner for its 20% general partner interest in this Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in this Partnership, as well as amounts distributed to the Managing General Partner for limited partnership units repurchased.



Distributions

Three months ended June 30,	Managing General Partner		Investor Partners		Total
2013	$	1,841	$	13,757	$	15,598
2012	770		6,856		7,626

Six months ended June 30,	Managing General Partner		Investor Partners		Total
2013	$	5,040	$	50,022	$	55,062
2012	1,483		13,282		14,765

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

The increase in distributions for the six months ended June 30, 2013 as compared to 2012 is primarily due to an increase in cash flows from operating activities during 2013.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

The increase in distributions for the three months ended June 30, 2013 as compared to 2012 is primarily due to an increase in cash flows from operating activities during 2013.

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture of approximately $220,000 including approximately $176,000 and $44,000 to the Investor Partners and the Managing General Partner, respectively.

Beginning in November 2009, when the Investor Partners' average annual rate of return fell below 12.8%, this 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 $5,983 and $1,470 for the six months ended June 30, 2013 and 2012, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02. The Managing General Partner's obligation under Section 4.02 expired in April 2013. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions, to this Partnership's financial statements included in the 2012 Form 10-K.

Off-Balance Sheet Arrangements

As of June 30, 2013, this 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 this Partnership's financial condition, 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 elsewhere in this report.

Recent Accounting Standards

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

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Index

PDC 2002-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 this 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 this Partnership's 2012 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a) Evaluation of Disclosure Controls and Procedures

As of ~~March~~June 3130, 2013, PDC, as Managing General Partner on behalf of this 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 this 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 this 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 this 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 this Partnership's disclosure controls and procedures were effective as of ~~March~~June 3130, 2013.

(b) Changes in Internal Control over Financial Reporting

During the three months ended ~~March~~June 3130, 2013, PDC, the Managing General Partner, made no changes in this 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 this 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 in May 2006, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of this Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases, of 10% of the initial subscription units.

The following table presents information about the Managing General Partner's limited partner unit repurchases during the three months ended ~~March~~June 3130, 2013:

Period	Total Number of Units Repurchased	Average Price Paid Per Unit
January 1 - 31, 2013	—	$	—
April 1-30, 2013	—	$	—
February 1 - 28, 2013	0.25	360
May 1-31, 2013	0.77	721
March 1 - 31, 2013	0.25	360
June 1-30, 2013	—	—
Total	0.5077	$—	~~360~~

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

- 22-

Index

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

(A West Virginia Limited Partnership)

Item 6. Exhibits Index

Incorporated by Reference

ExhibitNumber

Exhibit Description

Form

SEC FileNumber

Exhibit

Filing Date

FiledHerewith

10.1

Purchase and Sale Agreement by and among PDC Energy, Inc., affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated February 4, 2013.

10-Q

000-07246

10.1

5/1/2013

10.2

Amendment No. 1 to Purchase and Sale Agreement by and among PDC Energy, Inc., affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated May 30, 2013.

10-Q

000-07246

10.1

6/3/2013

31.1

Certification by Chief Executive Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) 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 this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) 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 this 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.

- 23-

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

PDC Energy, Inc.

By: /s/ James M. Trimble James M. TrimbleChief Executive Officer and Presidentof PDC Energy, Inc. ~~May~~August 1014, 2013

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	Chief Executive Officer and President	~~May~~August 1014, 2013
James M. Trimble	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~May~~August 1014, 2013
Gysle R. Shellum	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~May~~August 1014, 2013
R. Scott Meyers	PDC Energy, Inc. Managing General Partner of the Registrant
	(principal accounting officer)

- 24-

Filing Compare · PDC 2002 C LTD PARTNERSHIP