UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

~~For the~~OF ~~quarterly period ended September 30, 2009~~1934

For the quarterly period ended March 31, 2010

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

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-51220

PDC 2004-C Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	20-0547475
(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~~ Zip code)

(303) 860-5800

(Registrant's telephone number, including area code)

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

Yes TNo ¨ ~~No S~~

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

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ST

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

As of ~~November~~ 30March 31, ~~2009~~2010 the Partnership had 899.88 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page	~~Page~~
	PART I – FINANCIAL INFORMATION	~~PART I – FINANCIAL INFORMATION~~
Item 1.	Financial Statements (unaudited)	~~Condensed Financial Statements (unaudited)~~
		Condensed Balance Sheets	1
	Condensed Balance Sheets (unaudited)	2
		Condensed Statements of Operations	2
	Condensed Statements of Operations (unaudited)	3
		Condensed Statements of Cash Flows	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	~~Notes to Unaudited Condensed Financial Statements~~5	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~11	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~Quantitative and Qualitative Disclosures About Market Risk~~19	26
Item 4T.	Controls and Procedures	~~Controls and Procedures~~19	26
	PART II – OTHER INFORMATION	~~PART II – OTHER INFORMATION~~
Item 1.	Legal Proceedings	~~Legal Proceedings~~20	28
Item 1A.	Risk Factors	~~Risk Factors~~20	28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~Unregistered Sales of Equity Securities and Use of Proceeds~~20	28
Item 3.	Defaults Upon Senior Securities	~~Defaults Upon Senior Securities~~20	28
Item 4.	[Removed and Reserved]	~~Submission of Matters to a Vote of Security Holders~~20	28
Item 5.	Other Information	~~Other Information~~20	28
Item 6.	Exhibits	~~Exhibits~~21	29
	SIGNATURES	~~SIGNATURES~~22	30

Index

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2004-C Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“PDC’s”) strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

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

risks incident to the operation of natural gas and oil wells;

future production and development costs;

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

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

the effect of natural gas and oil derivatives activities;

conditions in the capital markets; and

losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (“SEC”) on March 15, 2010, (“2009 Form 10-K”), and the Partnership’s other filings with the SEC and public disclosures. The Partnership cautions you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

- 1 -

Index

PART I – FINANCIAL INFORMATION

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

PDC 2004-C Limited Partnership ~~Condensed Balance Sheets (unaudited)~~

	September 30,			December 31,
	2009			2008*
Assets
Current assets:
Cash and cash equivalents	$	197,165		$	71,549
Accounts receivable		86,380			132,868
Oil inventory		12,909			23,927
Due from Managing General Partner-derivatives		412,457			813,756
Due from Managing General Partner-other, net		151,797			710,170
Total current assets		860,708			1,752,270
Oil and gas properties, successful efforts method		19,921,685			19,885,279
Drilling advances to Managing General Partner		-			124,276
Oil and gas properties, at cost		19,921,685			20,009,555
Less: Accumulated depreciation, depletion and amortization		(8,945,239	)		(7,708,783	)
Oil and gas properties, net		10,976,446			12,300,772
Due from Managing General Partner-derivatives		22,580			274,993
Other assets		9,867			1,791
Total noncurrent assets		11,008,893			12,577,556
Total Assets	$	11,869,601		$	14,329,826
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	11,508		$	27,080
Due to Managing General Partner-derivatives		187,197			-
Total current liabilities		198,705			27,080
Due to Managing General Partner-derivatives		588,280			75,211
Asset retirement obligations		158,699			152,138
Total liabilities		945,684			254,429
Commitments and contingent liabilities
Partners' equity:
Managing General Partner		2,188,425			2,818,721
Limited Partners - 899.88 units issued and outstanding		8,735,492			11,256,676
Total Partners' equity		10,923,917			14,075,397
Total Liabilities and Partners' Equity	$	11,869,601		$	14,329,826

Condensed Balance Sheets

*Derived from audited December 31, 2008 balance sheet contained in the Partnership’s Form 10-K for the year ended December 31, 2008.(unaudited)

	March 31,			December 31,
	2010			2009*
Assets

Current assets:
Cash and cash equivalents	$	197,165		$	197,165
Accounts receivable		176,398			101,158
Oil inventory		10,614			16,430
Due from Managing General Partner-derivatives		286,834			219,167
Due from Managing General Partner-other, net		259,745			170,902
Total current assets		930,756			704,822


Oil and gas properties, successful efforts method, at cost		19,992,690			19,989,720
Less: Accumulated depreciation, depletion and amortization		(9,727,444	)		(9,307,929	)
Oil and gas properties, net		10,265,246			10,681,791

Due from Managing General Partner-derivatives		548,016			219,435
Other assets		15,540			12,682
Total noncurrent assets		10,828,802			10,913,908

Total Assets	$	11,759,558		$	11,618,730

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	18,039		$	13,845
Due to Managing General Partner-derivatives		250,658			216,885
Total current liabilities		268,697			230,730

Due to Managing General Partner-derivatives		673,237			625,688
Asset retirement obligations		227,250			223,913
Total liabilities		1,169,184			1,080,331

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		2,121,717			2,111,321
Limited Partners - 899.88 units issued and outstanding		8,468,657			8,427,078
Total Partners' equity		10,590,374			10,538,399

Total Liabilities and Partners' Equity	$	11,759,558		$	11,618,730

______________________________________

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-C Limited Partnership ~~Condensed Statements of Operations (unaudited)~~

	Three months ended September 30,					Nine months ended September 30,
	2009			2008		2009			2008
Revenues:
Oil and gas sales	$	294,791		$	772,998	$	889,252		$	2,462,203
Oil and gas price risk management (loss) gain, net		(244,630	)		1,449,682		(582,342	)		391,947
Total revenues		50,161			2,222,680		306,910			2,854,150
Operating costs and expenses:
Production and operating costs		134,483			230,358		387,615			674,984
Direct costs - general and administrative		73,977			3,081		361,220			18,453
Depreciation, depletion and amortization		403,840			268,051		1,236,456			828,452
Accretion of asset retirement obligations		2,187			2,068		6,561			6,204
Total operating costs and expenses		614,487			503,558		1,991,852			1,528,093
(Loss) income from operations		(564,326	)		1,719,122		(1,684,942	)		1,326,057
Interest expense		(412	)		-		(412	)		-
Interest income		6,607			7,927		18,382			25,364
Net (loss) income	$	(558,131	)	$	1,727,049	$	(1,666,972	)	$	1,351,421
Net (loss) income allocated to partners	$	(558,131	)	$	1,727,049	$	(1,666,972	)	$	1,351,421
Less: Managing General Partner interest in net (loss) income		(111,626	)		345,410		(333,394	)		270,284
Net (loss) income allocated to Investor Partners	$	(446,505	)	$	1,381,639	$	(1,333,578	)	$	1,081,137
Net (loss) income per Investor Partner unit	$	(496	)	$	1,535	$	(1,482	)	$	1,201
Investor Partner units outstanding		899.88			899.88		899.88			899.88

Condensed Statements of Operations

(unaudited)

	Three months ended March 31,
	2010		2009
Revenues:
Natural gas and oil sales	$	515,557	$	345,243
Commodity price risk management gain (loss), net		501,794		(30,960	)
Total revenues		1,017,351		314,283

Operating costs and expenses:
Natural gas and oil production costs		125,285		132,677
Direct costs - general and administrative		36,096		164,676
Depreciation, depletion and amortization		419,515		448,394
Accretion of asset retirement obligations		3,337		2,187
Total operating costs and expenses		584,233		747,934

Income (loss) from operations		433,118		(433,651	)

Interest income		-		6,064

Net income (loss)	$	433,118	$	(427,587	)

Net income (loss) allocated to partners	$	433,118	$	(427,587	)
Less: Managing General Partner interest in net income (loss)		86,624		(85,517	)
Net income (loss) allocated to Investor Partners	$	346,494	$	(342,070	)

Net income (loss) per Investor Partner unit	$	385	$	(380	)

Investor Partner units outstanding		899.88		899.88

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-C Limited Partnership ~~Condensed Statements of Cash Flows (unaudited)~~

	Nine months ended September 30,
	2009			2008
Cash flows from operating activities:
Net (loss) income	$	(1,666,972	)	$	1,351,421
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,236,456			828,452
Accretion of asset retirement obligations		6,561			6,204
Unrealized loss (gain) on derivative transactions		1,353,978			(544,599	)
Changes in operating assets and liabilities:
Decrease in accounts receivable		46,488			119,678
Increase in accounts receivable - other		-			(24,981	)
Decrease (increase) in oil inventory		11,018			(28,357	)
Increase in other assets		(8,076	)		(642	)
(Decrease) increase in accounts payable and accrued expenses		(15,572	)		29,739
Decrease (increase) in due from Managing General Partner - other, net		558,373			(20,323	)
Net cash provided by operating activities		1,522,254			1,716,592
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(36,406	)		(9,925	)
Proceeds from drilling advance refund from Managing General Partner		124,276
Net cash provided by (used in) investing activities		87,870			(9,925	)
Cash flows from financing activities:
Distributions to Partners		(1,484,508	)		(1,699,338	)
Net cash used in financing activities		(1,484,508	)		(1,699,338	)
Net increase in cash and cash equivalents		125,616			7,329
Cash and cash equivalents, beginning of period		71,549			39,240
Cash and cash equivalents, end of period	$	197,165		$	46,569

Condensed Statements of Cash Flows

(unaudited)

	Three months ended March 31,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	433,118		$	(427,587	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		419,515			448,394
Accretion of asset retirement obligations		3,337			2,187
Unrealized (gain) loss on derivative transactions		(314,926	)		375,179
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(75,240	)		39,704
Decrease in oil inventory		5,816			3,252
Increase in other assets		(2,858	)		(3,046	)
Increase (decrease) in accounts payable and accrued expenses		4,194			(8,866	)
Increase in due from Managing General Partner - other, net		(88,843	)		(11,080	)
Net cash provided by operating activities		384,113			418,137

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(2,970	)		(25,637	)
Net cash used in investing activities		(2,970	)		(25,637	)

Cash flows from financing activities:
Distributions to Partners		(381,143	)		(391,179	)
Net cash used in financing activities		(381,143	)		(391,179	)

Net increase in cash and cash equivalents		-			1,321
Cash and cash equivalents, beginning of period		197,165			71,549
Cash and cash equivalents, end of period	$	197,165		$	72,870

See accompanying notes to unaudited condensed financial statements.

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September 30~~March 31, ~~2009~~2010

(unaudited)

Note 1−General and Basis of Presentation

The PDC 2004-C Limited Partnership ~~(the “Partnership” or the “Registrant”)~~ was organized as a limited partnership on July 28, 2004, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties. Upon completion of the sale of Partnership units on August 4, 2004, the Partnership was funded and commenced its business operations. The Partnership owns natural gas and oil wells located in Colorado, and from the wells, the Partnership produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 12.11 units of limited partner interests and 887.77 units of additional general partner interests at $20,000 per unit. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a Nevada Corporation, is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner,” ~~“MGP”~~ or “PDC”) and has a 20% Managing General Partner ownership in the Partnership. Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 20% to the Managing General Partner.

As of ~~September~~ 30March 31, ~~2009~~2010, there were 663 Investor Partners. As of ~~September 30,~~March ~~2009~~31, 2010 the Managing General Partner has repurchased 1315.7398 units of the total 899.88 outstanding units of Partnership interests from Investor Partners at an average price of $98,~~108~~728 per unit ~~through September 30, 2009~~ and, as a result, participates in the sharing of revenues, costs and cash distributions as both an ~~Investor~~ ~~Partner~~investor partner and as the Managing General Partner.

The Managing General Partner ~~is authorized~~, under the terms of the Drilling and Operating Agreement (the “D&O Agreement”), has full authority to conduct the Partnership’s business and actively manage the Partnership. The Partnership expects continuing operations of its oil and natural gas properties until such time that a well is depleted or becomes uneconomical to produce, at which time that well will be plugged and abandoned. The Partnership’s ~~business~~maximum term of existence extends through December 31, 2055, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

~~The~~ In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements ~~have~~contain ~~been~~all ~~prepared without~~adjustments ~~audit~~(consisting of only normal recurring adjustments) necessary for a fair presentation of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America, or ("U.S., ~~for~~GAAP") ~~interim financial information~~ and with the instructions to Form 10-Q and Article 810 of Regulation S-X of the ~~Securities and Exchange Commission, or~~ SEC. Accordingly, pursuant to ~~certain~~such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. InThe information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s ~~opinion,~~audited ~~the~~financial ~~accompanying~~statements ~~interim~~and ~~unaudited~~notes ~~condensed~~thereto ~~financial statements~~included ~~contain~~in ~~all~~the ~~adjustments~~Partnership’s ~~(consisting~~2009 ofForm ~~only~~10-K. The ~~normal~~Partnership’s ~~recurring adjustments)~~accounting ~~necessary~~policies are described in the Notes to ~~present~~Financial ~~fairly~~Statements in the Partnership'’s ~~financial~~2009 ~~position, results~~Form of10-K ~~operations~~ and ~~cash~~updated, ~~flows~~as ~~for~~necessary, ~~the~~in ~~periods~~this ~~presented~~Form 10-Q. The ~~interim~~ results of operations ~~and cash flows~~ for the ~~nine~~three months ended ~~September 30~~March 31, ~~2009~~2010, and ~~2008~~the cash flows for the same period, are not necessarily indicative of the results to be expected for the full year or any other future period.

The accompanying interim unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership's Form 10-K for the year ended December 31, ~~2008~~2009, as filed with the SEC on ~~October~~March 2615, ~~2009~~2010 (“the ~~2008~~2009 Form 10-K”).

~~Note 2−Recent~~The ~~Accounting Standards~~Managing General Partner has evaluated the Partnership’s activities subsequent to March 31, 2010 and has concluded that no material subsequent events have occurred that would require recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.

~~Recently~~- ~~Adopted~~5 ~~Accounting Standards~~-

Accounting Standards Codification

In June 2009, the Financial Accounting Standards Board, or FASB, issued the FASB Accounting Standards Codification™ (the “Codification”), thereby establishing the Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles, or GAAP. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, the FASB will issue Accounting Standards Updates. Accounting Standards Updates will not be authoritative in their own right as they will only serve to update the Codification. These changes and the Codification itself do not change GAAP. Effective July 1, 2009, the Partnership adopted the Codification. Other than the manner in which new accounting guidance is referenced, the adoption of the Codification did not have any impact on the Partnership’s accompanying interim unaudited condensed financial statements.

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September 30~~March 31, ~~2009~~2010

(unaudited)

~~Subsequent Events~~Note 2−Recent Accounting Standards

InRecently ~~May 2009,~~Adopted ~~the~~Accounting FASB issued changes regarding subsequent events, which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. Specifically, the guidance sets forth the period after the balance sheet date during which the Managing General Partner should evaluate events or transactions that may occur for potential recognition or disclosure in the Partnership’s financial statements, the circumstances under which the Partnership should recognize events or transactions occurring after the balance sheet date in the Partnership’s financial statements, and the disclosures that the Partnership should make about events or transactions that occurred after the balance sheet date. The Partnership adopted the guidance as of June 30, 2009. See Note 7, Subsequent Events.Standards

Business Combinations

In December 2007, the FASB issued changes regarding the accounting for business combinations. The new changes require:

· an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values;

· disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination;

· acquisition-related costs be expensed as incurred.

The changes also amend the accounting for income taxes to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. Further, the changes amend the accounting for income taxes to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.

In April 2009, the FASB again issued changes to the accounting for business combinations. These changes apply to all assets acquired and liabilities assumed in a business combination that arise from contingencies and require:

· an acquirer to recognize at fair value, at the acquisition date, an asset acquired or liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period otherwise the asset or liability should be recognized at the acquisition date if certain defined criteria are met;

· contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination be recognized initially at fair value;

· subsequent measurements of assets and liabilities arising from contingencies be based on a systematic and rational method depending on their nature and contingent consideration arrangements be measured subsequently; and

· disclosures of the amounts and measurements basis of such assets and liabilities and the nature of the contingencies.

The changes above became effective for acquisitions completed on or after January 1, 2009; however, the income tax changes became effective as of that date for all acquisitions, regardless of the acquisition date. The Partnership adopted these changes effective January 1, 2009, for which they will be applied prospectively in the Partnership’s accounting for future acquisitions, if any. This adoption had no impact on the Partnership’s accompanying interim unaudited condensed financial statements.

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2009

(unaudited)

Consolidation – Noncontrolling Interest in a Subsidiary

In December 2007, the FASB issued changes regarding the nature and classification of the noncontrolling interest in a subsidiary in the consolidated financial statements. The changes require the accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. Additionally, the changes establish reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. The Partnership adopted these changes effective January 1, 2009. The Partnership’s adoption of this guidance had no material impact on the Partnership’s accompanying interim unaudited condensed financial statements.

Fair Value Measurements and Disclosures

In ~~February~~ ~~2008~~January 2010, the ~~FASB~~Financial ~~delayed~~Accounting byStandards ~~one~~Board ~~year~~ (~~to January 1, 2009~~“FASB”) ~~the~~issued ~~fair~~changes ~~value measurements~~clarifying ~~and~~existing disclosure requirements ~~for~~related ~~nonfinancial~~to ~~assets~~fair ~~and liabilities,~~value ~~except~~measurements. The ~~those~~update ~~that~~also ~~are~~added ~~recognized~~a ornew ~~disclosed~~requirement atto disclose fair value transfers in ~~the financial~~and ~~statements~~out onof aLevels ~~recurring~~1 ~~basis~~and ~~(at~~2 ~~least~~and ~~annually).~~describe ~~The~~the ~~January~~reasons ~~1, 2009,~~for ~~adoption of~~ the ~~fair~~transfers. The ~~value~~adoption ~~measurements~~of ~~and~~these ~~disclosure~~changes ~~requirements~~as ~~for the~~of ~~Partnership’s~~January ~~nonfinancial~~1, ~~assets~~2010, ~~and liabilities~~ did not have a material impact on the Partnership’s accompanying ~~interim~~ unaudited condensed financial statements. ~~See Note 4, Fair Value Measurements.~~

Derivatives and Hedging Disclosures

In March 2008, the FASB issued changes regarding the disclosure requirements for derivative instruments and hedging activities. Pursuant to the changes, enhanced disclosures are required to provide information about (a) how and why the Partnership uses derivative instruments, (b) how the Partnership accounts for derivative instruments and related hedged items and (c) how derivative instruments and related hedged items affect the Partnership’s financial position, financial performance and cash flows. The Partnership adopted these changes effective January 1, 2009. The adoption did not have a material impact on the Partnership’s accompanying interim unaudited condensed financial statements. See Note 5, Derivative Financial Instruments.

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

In ~~August 2009~~January 2010, the FASB issued changes ~~regarding~~related to fair value measurements ~~and~~requiring ~~disclosures to~~gross ~~reduce~~presentation ~~potential ambiguity in financial reporting when measuring the fair value~~ of ~~liabilities. These~~activities ~~changes~~within ~~clarify existing guidance that in circumstances in which a quoted price in an active market for~~ the ~~identical liability~~Level is3 ~~not~~roll ~~available~~forward, anwhereby ~~entity~~entities ismust ~~required~~present toseparately ~~measure~~information ~~fair~~about ~~value using either a valuation technique that uses a quoted price of either a similar liability or a quoted price of an identical or similar liability when traded as an asset~~purchases, ~~or another valuation technique that is consistent with the principles of fair value measurements~~sales, ~~such~~issuances asand ~~an income approach (e~~settlements.~~g., present value technique).~~ This ~~guidance~~change ~~also~~will ~~states~~be ~~that~~effective ~~both a quoted price in an active market~~ for the ~~identical~~Partnership’s ~~liability~~financial ~~and~~statements aissued ~~quoted price~~ for ~~the~~annual ~~identical liability~~reporting ~~when~~periods ~~traded~~beginning asafter anDecember ~~asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. These changes become effective for the Partnership on October 1~~15, ~~2009~~2010. The Partnership ~~has~~does not ~~determined~~expect ~~the~~adoption ~~impact,~~of ~~if any, that~~ these changes ~~will~~to have a material effect on the Partnership’s financial statements and related disclosures.

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Index

Consolidation – Variable Interest Entities

In June 2009, the FASB issued changes surrounding an entity’s analysis to determine whether any of its variable interests constitute controlling financial interests in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics:

· the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and

· the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity.

Additionally, the entity is required to assess whether it has an implicit financial responsibility to ensure that a variable interest entity operates as designed when determining whether it has the power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance. The guidance also requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. These changes are effective for the Partnership’s financial statements issued for fiscal years beginning after November 15, 2009, with earlier adoption prohibited. The Partnership is evaluating the impact that the adoption of these changes will have on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.

Modernization of Oil and Gas Reporting

In January 2009, the SEC published its final rule regarding the modernization of oil and gas reporting (the "final rule"), which modifies the SEC’s reporting and disclosure rules for oil and natural gas reserves. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and natural gas reserves to a 12-month average of the first day of the month price for each month within the reporting period and also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The final rule also reiterates that the definition of proved undeveloped oil and gas reserves require that the Partnership adopt a development plan with respect to these reserves. Additionally, the final rule reiterates the documentation requirements which must be met to classify reserves as proved undeveloped. The development plan which has been adopted should indicate that these reserves are scheduled to be developed within five years, unless specific circumstances justify a longer time.

The revised reporting and disclosure requirements are effective for the Partnership’s Annual Report on Form 10-K for the year ending December 31, 2009. Early adoption is not permitted. The Partnership is evaluating the impact that adoption of this final rule will have on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.

Note 3−Transactions with Managing General Partner and Affiliates

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

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item – Due from (to) Managing General Partner-7-other, net which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.

	March 31,			December 31,
	2010			2009

Natural gas and oil sales revenues collected from the Partnership's third-party customers	$	169,894		$	161,879
Commodity price risk management, realized gains		131,742			158,936
Other (1)		(41,891	)		(149,913	)
Total Due from Managing General Partner-other, net	$	259,745		$	170,902

(1)

All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner.

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September 30~~March 31, ~~2009~~2010

(unaudited)

The ~~fair value~~following oftable ~~the~~presents Partnership’s ~~portion~~transactions, ofexcluding ~~unexpired~~ derivative ~~instruments~~transactions ~~is recorded~~which onare ~~the~~more ~~balance~~fully ~~sheet~~detailed ~~under~~in ~~the~~Note ~~captions~~5, ~~“Due~~Derivative ~~from~~Financial Instruments, with the Managing General Partner~~–derivatives,”~~ inand ~~the~~its ~~case~~affiliates offor ~~net~~three ~~unrealized~~months ~~gains~~ended orMarch 31, 2010 and 2009. “~~Due~~Well tooperations ~~Managing General~~and ~~Partner–derivatives~~maintenance” and “Gathering, compression and processing fees” are included in ~~the~~“Natural ~~case~~gas ofand ~~net~~oil ~~unrealized~~production ~~losses~~costs” on the statements of operations.

Undistributed oil and natural gas revenues collected by the Managing General Partner from the Partnership’s customers in the amount of $122,195 and $256,773 as of September 30, 2009 and December 31, 2008, respectively, are included in the balance sheet caption “Due from Managing General Partner - other, net.” Realized gains or losses from derivative transactions that have not yet been distributed to the Partnership are included in the balance sheet captions “Due from Managing General Partner-other, net” or “Due to Managing General Partner-other, net,” respectively. Undistributed realized gains amounted to $130,334 and $283,224 as of September 30, 2009 and December 31, 2008, respectively. All other unsettled transactions between the Partnership and the Managing General Partner are recorded net on the balance sheet under the caption “Due from (to) Managing General Partner – other, net.”

	Three months ended March 31,
	2010		2009

Well operations and maintenance	$	93,677	$	91,498
Gathering, compression and processing fees		16,989		22,965
Direct costs - general and administrative		36,096		164,676
Cash distributions*		81,642		81,312

~~The following~~*Cash ~~table~~distributions ~~presents~~include ~~transactions~~$5,414 ~~with~~during the ~~Managing~~three ~~General~~months ~~Partner~~ended March 31, 2010, and ~~its affiliates~~$3,076 ~~for~~during the ~~periods~~three ~~described~~months ~~below. “Well~~ended ~~operations~~March ~~and maintenance”~~31, ~~and “Gathering~~2009, ~~compression~~related ~~and~~to ~~processing~~equity ~~fees”~~cash ~~are~~distributions ~~included~~on ~~in “Production~~Investor ~~and~~Partner ~~operating~~units ~~costs”~~repurchased onby ~~the Statements of Operations~~PDC. ~~Additionally,~~For ~~refer~~additional todisclosure ~~Note~~regarding 5,the ~~Derivative~~Unit ~~Financial Instruments~~Repurchase ~~for~~Program, ~~derivative~~refer ~~transactions~~to ~~between~~Note ~~the~~1, ~~Partnership~~General and ~~the Managing~~Basis ~~General~~of ~~Partner~~Presentation.

	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
Well operations and maintenance	$	96,873	$	142,885	$	276,402	$	404,264
Gathering, compression and processing fees		20,852		22,818		63,130		65,505
Direct costs - general and administrative		73,977		3,081		361,220		18,453
Cash distributions*		124,828		120,451		309,828		350,428

*Cash distributions include $4,588 and $12,926 during the three and nine months ended September 30, 2009, respectively, and $3,893 and $10,561 during the three and nine months ended September 30, 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC. For additional disclosure regarding the Unit Repurchase Program, refer to Note 1, General and Basis of Presentation.

Distributions to Partners in 2009 were impacted by several non-recurring items. Receivables collected from the Managing General Partner for the over-withholding of production taxes related to Partnership production prior to 2007 including accrued interest thereon increased distributions by $0.6 million. In addition, the Partnership’s payment to the Managing General Partner for royalty settlement costs of approximately $14,000 decreased distributions during the period. Cash distribution to the partners includes $0.2 million paid on the behalf of Investor Partners, to the Internal Revenue Service and state taxing authorities as a part of a comprehensive settlement agreement with taxing agencies. Both amounts had been previously accrued by the Partnership in “Due from (to) Managing General Partner – other, net.”

Note 4−Fair Value Measurements

~~Determination~~Derivative ofFinancial ~~Fair Value~~Instruments. The Partnership’s measures fair value ~~measurements~~based ~~are~~upon ~~estimated~~quoted ~~pursuant~~market toprices, awhere ~~fair~~available. The ~~value hierarchy~~valuation ~~that~~determination ~~requires~~includes: (1) identification of the ~~Partnership~~inputs to ~~maximize~~ the ~~use~~fair ofvalue ~~observable~~methodology ~~inputs and~~through ~~minimize~~ the ~~use~~review of ~~unobservable~~counterparty ~~inputs~~statements ~~when~~and ~~measuring~~other ~~fair value. The~~supporting ~~valuation~~documentation, ~~hierarchy~~(2) isdetermination ~~based~~of ~~upon~~ the ~~transparency~~validity of ~~inputs~~ to the ~~valuation~~source of anthe ~~asset~~inputs, or(3) ~~liability~~corroboration as of the ~~measurement~~original ~~date, giving~~source ~~the~~of ~~highest~~inputs ~~priority~~through access to ~~quoted~~multiple ~~prices~~quotes, inif ~~active~~available, ~~markets~~or ~~(Level~~other 1)information and ~~the lowest~~(4) ~~priority~~monitoring tochanges ~~unobservable~~in ~~data~~valuation ~~(Level~~methods 3)and assumptions. InThe ~~some~~methods ~~cases,~~described ~~the inputs~~above ~~used~~may toproduce ~~measure~~a fair value ~~might~~calculation ~~fall~~that inmay ~~different~~not ~~levels~~be indicative of ~~the~~future fair ~~value~~ ~~hierarchy~~values. The ~~lowest~~valuation ~~level~~determination ~~input~~also ~~that~~gives isconsideration ~~significant~~ to anonperformance ~~fair value~~risk ~~measurement~~on Partnership liabilities in ~~its~~addition ~~entirety~~to ~~determines~~nonperformance risk on PDC’s own business interests and liabilities, as well as the ~~applicable~~credit ~~level~~standing of derivative instrument counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in PDC’s credit facility agreement, as counterparties to the ~~fair value~~Partnership’s ~~hierarchy~~derivative contracts. ~~Assessing~~The Managing General Partner has evaluated the ~~significance~~credit risk of athe ~~particular~~counterparties ~~input~~holding to the ~~fair~~Partnership’s ~~value~~derivative ~~measurement~~assets inusing ~~its~~relevant ~~entirety~~credit ~~requires~~market ~~judgment~~default rates, ~~considering factors~~giving ~~specific~~consideration to amounts outstanding for each counterparty and the ~~asset~~duration orof ~~liability~~each outstanding derivative position. Based on the Managing General Partner’s evaluation as of March 31, ~~and~~2010, ~~may~~the ~~affect~~impact of non-performance risk on the ~~valuation~~fair value of the Managing General Partner’s derivative assets and liabilities ~~and~~was ~~their~~not ~~placement~~significant. Validation ~~within~~of the Partnership’s contracts’ fair ~~value~~values ~~hierarchy levels~~are performed internally and while the Managing General Partner uses common industry practices to develop valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values. ~~The~~While ~~three~~the ~~levels~~Managing ofGeneral ~~inputs~~Partner ~~that~~believes ~~may~~these bevaluation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to ~~measure~~determine the fair value ~~are~~of ~~defined~~certain ~~as:~~financial instruments could result in a different estimate of fair value.

-8 7 -

Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September 30~~March 31, ~~2009~~2010

(unaudited)

·The ~~Level~~following 1table –presents, ~~Quoted~~by ~~prices~~hierarchy ~~(unadjusted)~~level, inthe ~~active~~Partnership’s ~~markets for identical assets or liabilities. Included in Level 1 are commodity~~ derivative financial instruments, ~~for~~including ~~New~~both ~~York~~current ~~Mercantile~~and ~~Exchange,~~non-current orportions ~~NYMEX,~~measured ~~based~~at ~~natural~~fair ~~gas swaps~~value.

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

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

As of December 31, 2009
Assets:
Commodity based derivatives	$	221,143		$	217,459		$	438,602
Total assets		221,143			217,459			438,602

Liabilities:
Commodity based derivatives		(16,231	)		(32,805	)		(49,036	)
Basis protection derivative contracts		-			(793,537	)		(793,537	)
Total liabilities		(16,231	)		(826,342	)		(842,573	)

Net asset (liability)	$	204,912		$	(608,883	)	$	(403,971	)

As of March 31, 2010
Assets:
Commodity based derivatives	$	763,981		$	70,869		$	834,850
Total assets		763,981			70,869			834,850

Liabilities:
Commodity based derivatives		-			(31,357	)		(31,357	)
Basis protection derivative contracts		-			(892,538	)		(892,538	)
Total liabilities		-			(923,895	)		(923,895	)

Net asset (liability)	$	763,981		$	(853,026	)	$	(89,045	)

·The ~~Level~~following 3table –presents ~~Unobservable inputs for~~ the ~~asset~~changes orof ~~liability, including situations where there is little, if any, market activity for~~ the ~~asset or liability. Included in Level 3 are the~~ Partnership’s ~~commodity~~Level 3 derivative financial instruments ~~for~~measured ~~Colorado~~on ~~Interstate~~a ~~Gas,~~recurring ~~or CIG, based fixed-price natural gas swaps, collars and floors, oil swaps, and natural gas~~ basis ~~protection swaps.~~:

Derivative Financial Instruments. The Partnership measures fair value based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses two investment grade financial institutions as counterparties to its derivative contracts, who hold the majority of the Managing General Partner’s derivative assets. The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties holding its derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, the Partnership has determined that the impact of counterparty non-performance on the fair value of the Partnership’s derivative instruments is insignificant. As of September 30, 2009, no adjustment for credit risk was recorded by the Partnership. Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

	Three months ended
	March 31, 2010
Fair value, net liability, as of December 31, 2009	$	(608,883	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		(57,275	)
Settlements		(186,868	)
Fair value, net liability, as of March 31, 2010	$	(853,026	)

Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2010 included in statement of operations line item:
Commodity price risk management, net	$	(71,032	)

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

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2009

(unaudited)

	Level 1			Level 3			Total
As of December 31, 2008
Assets:
Commodity based derivatives	$	-		$	1,088,749		$	1,088,749
Total assets		-			1,088,749			1,088,749
Liabilities:
Basis protection derivative contracts		-			(75,211	)		(75,211	)
Total liabilities		-			(75,211	)		(75,211	)
Net asset	$	-		$	1,013,538		$	1,013,538
As of September 30, 2009
Assets:
Commodity based derivatives	$	1,927		$	433,110		$	435,037
Total assets		1,927			433,110			435,037
Liabilities:
Commodity based derivatives		(66,232	)		(23,844	)		(90,076	)
Basis protection derivative contracts		-			(685,401	)		(685,401	)
Total liabilities		(66,232	)		(709,245	)		(775,477	)
Net liability	$	(64,305	)	$	(276,135	)	$	(340,440	)

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2009

(unaudited)

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

	Nine months ended
	September 30, 2009
Fair value, net asset, as of December 31, 2008	$	1,013,538
Changes in fair value included in statement of operations line item:
Oil and gas price risk management loss, net		(518,037	)
Settlements		(771,636	)
Fair value, net liability, as of September 30, 2009	$	(276,135	)
Change in unrealized gains (losses) relating to assets (liabilities) still held as of September 30, 2009, included in statement of operations line item:
Oil and gas price risk management, net	$	(666,143	)

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

Non-Derivative Assets and Liabilities. The carrying values of the financial instruments comprising ~~“Cash~~current ~~and~~assets ~~cash equivalents,” “Accounts receivable,” “Accounts payable~~ and ~~accrued~~current ~~expenses”~~liabilities ~~and “Due to (from) Managing General Partner-other, net”~~ approximate fair value due to the short-term maturities of these instruments.

The Partnership periodically assesses its proved oil and gas properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon estimated prices at which the Partnership reasonably estimates the commodity to be sold. The estimates of future prices may differ from current market prices of oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs may result in a triggering event and, therefore, a possible impairment of the Partnership’s oil and natural gas properties. If, when assessing impairment, net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair value. During the nine months ended September 30, 2009 and 2008, there were no triggering events; therefore, no impairment of oil and gas properties was recognized.

The Partnership accounts for asset retirement obligations by recording the estimated fair value of the plugging and abandonment obligations when incurred, at the time when the well is completely drilled. The Partnership estimates the fair value of the plugging and abandonment obligations based on a discounted cash flows analysis. Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Periodically, the liabilities are accreted for the change in present value, through charges to “Accretion of asset retirement obligations” on the statement of operations. The initial capitalized costs are depleted based on the useful lives of the related assets, through charges to depreciation, depletion and amortization, or DD&A. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2009

(unaudited)

Note 5−Derivative Financial Instruments

~~The Partnership~~As ~~is exposed to the effect~~ of ~~market~~March ~~fluctuations~~31, in2010, the ~~prices~~Partnership ofhad ~~oil and~~derivative ~~natural~~instruments, ~~gas. Price~~comprised ~~risk~~of ~~represents~~commodity ~~the~~collars, ~~potential~~commodity ~~risk~~fixed-price ofswaps ~~loss from~~and ~~adverse~~basis ~~changes~~protection swaps, in ~~the~~place ~~market~~for ~~price~~a portion of ~~oil~~its ~~and~~anticipated ~~natural~~production ~~gas commodities. The~~through ~~Managing~~2013 ~~General~~for ~~Partner~~a ~~employs~~total ~~established policies~~of ~~and~~674,818 ~~procedures~~MMbtu toof ~~manage~~natural ~~the~~gas ~~risks~~and ~~associated~~5,766 ~~with~~Bbls ~~these~~of ~~market fluctuations using derivative instruments~~oil. Partnership policy prohibits the use of ~~oil and~~ natural gas and oil derivative instruments for speculative purposes.

~~The Partnership~~- ~~recognizes~~8 all derivative instruments as either assets or liabilities on the accompanying interim unaudited condensed balance sheets at fair value. The Partnership has elected not to designate any of the Partnership’s derivative instruments as hedges. Accordingly, changes in the fair value of those derivative instruments allocated to the Partnership are recorded in the Partnership’s statements of operations. Changes in the fair value of derivative instruments related to the Partnership’s oil and gas sales activities are recorded in “Oil and gas price risk management, net.”-

Valuation of a contract’s fair value is performed internally. While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in different fair values. See Note 4, Fair Value Measurements, for a discussion of how the Managing General Partner determines the fair value of the Partnership’s derivative instruments.

As of September 30, 2009, the Managing General Partner had derivative contracts in place for a portion of the Partnership’s anticipated production through 2012 for a total of 380 MMbtu of natural gas and 8 MBbls of crude oil. During late October 2009, the Managing General Partner entered into additional NYMEX fixed-price gas swaps (ranging from $6.67 to $7.11 per MMbtu) and NYMEX gas collars (floors ranging from $6.00 to 6.10 and ceiling ranging from $8.27 to $8.60 per MMbtu) covering all monthly periods from November 2010 to December 2013. The Partnership will be allocated positions by the Managing General Partner for MMbtu’s equal to the number of remaining MMbtu’s of CIG basis protection swaps at September 30, 2009 which were not previously covered by NYMEX fixed-price gas swaps or gas collars.

Derivative Strategies. The Partnership’s results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative contracts.

For Partnership oil and gas sales, the Managing General Partner enters into, for a portion of the Partnership’s production, derivative contracts to protect against price declines in future periods. While these derivatives are structured to reduce exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price increases in the physical market. The Partnership believes the derivative instruments in place continue to be effective in achieving the risk management objectives for which they were intended.

As of September 30, 2009, the Partnership’s oil and natural gas derivative instruments were comprised of commodity collars, commodity swaps and basis protection swaps.

· Collars contain a fixed floor price (put) and ceiling price (call). If the market price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and market price from the counterparty. If the market price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and market price to the counterparty. If the market price is between the call and put strike price, no payments are due to or from the counterparty.

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Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September 30~~March 31, ~~2009~~2010

(unaudited)

·The ~~Swaps~~following ~~are~~table ~~arrangements~~summarizes ~~that guarantee a fixed price. If~~ the ~~market~~location ~~price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser~~ and ~~receives~~fair ~~the~~value ~~difference~~amounts ~~between~~of the ~~market~~Partnership’s ~~price~~derivative ~~and~~instruments ~~the~~in ~~fixed contract price from~~ the ~~counterparty.~~accompanying Ifbalance the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the market price and the fixed contract price to the counterpartysheets.

· Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

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

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	286,834		$	219,167

	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		548,016			219,435

Total Derivative Assets			$	834,850		$	438,602

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(7,478	)	$	(16,640	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(243,180	)		(200,245	)
	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(23,879	)		(32,397	)

	Basis protection contracts	Due to Managing General Partner-derivatives		(649,358	)		(593,291	)

Total Derivative Liabilities			$	(923,895	)	$	(842,573	)

~~The following~~(1) ~~table~~As ~~summarizes~~of ~~the~~March ~~location~~31, 2010 and ~~fair~~December ~~value~~31, ~~amounts~~2009, none of the Partnership’s derivative instruments inwere ~~the~~designated ~~accompanying balance sheets as of September 30, 2009, and December 31, 2008~~hedges.

			Fair Value
		Balance Sheet	September 30,			December 31,
Derivative instruments not designated as hedge (1):		Line Item	2009			2008
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	412,457		$	813,756
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		22,580			274,993
Total Derivative Assets			$	435,037		$	1,088,749
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	(58,751	)	$	-
	Basis protection contracts	Due to Managing General Partner-derivatives		(128,446	)		-
	Non Current
	Commodity contracts	Due to Managing General Partner-derivatives		(31,325	)		-
	Basis protection contracts	Due to Managing General Partner-derivatives		(556,955	)		(75,211	)
Total Derivative Liabilities			$	(775,477	)	$	(75,211	)

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three months ended March 31, 2010 and 2009.

(1) As of September 30, 2009 and December 31, 2008, none of the Partnership’s derivative instruments were designated hedges.

	Three months ended March 31,
	2010							2009
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total

Commodity price risk management, net
Realized gains	$	173,111		$	13,757	$	186,868	$	284,070		$	60,149		$	344,219
Unrealized (losses) gains		(173,111	)		488,037		314,926		(284,070	)		(91,109	)		(375,179	)
Total commodity price risk management gain (loss), net	$	-		$	501,794	$	501,794	$	-		$	(30,960	)	$	(30,960	)

~~-13-~~Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Partnership to credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts. To date, the Partnership has experienced no counterparty default losses.

- 9 -

Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

~~September 30~~March 31, ~~2009~~2010

(unaudited)

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three months and nine months ended September 30, 2009 and 2008.

	Three months ended September 30,
	2009									2008
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total			Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period		Total
Oil and gas price risk management, net
Realized gains (losses)	$	201,847		$	(2,979	)	$	198,868		$	(168,952	)	$	211,677	$	42,725
Unrealized (losses) gains		(201,847	)		(241,651	)		(443,498	)		168,952			1,238,005		1,406,957
Total oil and gas price risk management (loss) gain, net	$	-		$	(244,630	)	$	(244,630	)	$	-		$	1,449,682	$	1,449,682

	Nine months ended September 30,
	2009									2008
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total			Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total
Oil and gas price risk management, net
Realized gains (losses)	$	599,692		$	171,944		$	771,636		$	(48,823	)	$	(103,829	)	$	(152,652	)
Unrealized (losses) gains		(599,692	)		(754,286	)		(1,353,978	)		48,823			495,776			544,599
Total oil and gas price risk management (loss) gain, net	$	-		$	(582,342	)	$	(582,342	)	$	-		$	391,947		$	391,947

Concentration of Credit Risk. A significant portion of the Partnership’s liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing oil and natural gas. These arrangements expose the Partnership to credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses two financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the derivative contracts.

Note 6−Commitments and Contingencies

~~Colorado~~Stormwater ~~Royalty Settlement~~Permit. On ~~May~~December 298, ~~2007~~2008, ~~Glen~~the ~~Droegemueller,~~Managing ~~individually and~~General asPartner ~~representative~~received ~~plaintiff~~a onNotice ~~behalf~~ of ~~all~~Violation ~~others~~/Cease ~~similarly~~and ~~situated, filed~~Desist aOrder ~~class~~(the ~~action~~“Notice”) ~~complaint~~from ~~against~~ the ~~Managing~~Colorado ~~General~~Department ~~Partner~~of inPublic Health and Environment (the ~~District~~ ~~Court~~“CDPHE”), ~~Weld~~related ~~County,~~to ~~Colorado~~the ~~alleging~~stormwater ~~that~~permit for the Garden Gulch Road. The Managing General Partner ~~underpaid~~ ~~royalties~~manages onthis ~~natural~~private ~~gas~~road ~~produced~~for ~~from~~Garden ~~wells~~Gulch ~~operated~~LLC. The ~~by the~~ Managing General Partner inis ~~parts~~one of ~~the~~eight ~~State~~users of ~~Colorado~~this ~~(the~~road, ~~“Droegemueller Action”). The~~all ~~plaintiff~~of ~~sought~~which ~~declaratory~~are ~~relief~~oil and togas ~~recover~~companies ~~an unspecified~~operating ~~amount~~in ofthe ~~compensation~~Piceance ~~for~~Basin ~~underpayment~~ of ~~royalties~~Colorado. Operating ~~paid~~expenses, byincluding ~~the Managing~~amounts ~~General~~arising ~~Partner~~from ~~pursuant~~this tonotice, ~~leases. The~~if ~~Managing~~any, ~~General~~are ~~Partner moved~~allocated among the ~~case~~users toof ~~Federal~~the ~~Court~~road onbased ~~June~~upon ~~28,~~their ~~2007~~respective usage. On The ~~October~~Partnership ~~10,~~has ~~2008,~~seven ~~the court~~wells ~~preliminarily~~in ~~approved~~this aregion. The ~~settlement~~Notice ~~agreement~~alleges ~~between~~a ~~the~~deficient ~~plaintiffs~~ and ~~the~~/or ~~Managing~~incomplete ~~General~~stormwater ~~Partner~~management plan, onfailure ~~behalf~~to ofimplement ~~itself~~best ~~and~~management ~~the~~practices ~~Partnership. Although~~and ~~the~~failure ~~Partnership~~to ~~was~~conduct ~~not~~required ~~named~~permit asinspections. The aNotice ~~party~~requires incorrective ~~the~~action ~~suit,~~and ~~the lawsuit~~ states that ~~this~~the ~~action~~recipient ~~relates~~shall tocease ~~all~~and ~~wells~~desist ~~operated~~such byalleged ~~the~~violations. The ~~Managing~~Notice ~~General Partner,~~states ~~which~~that ~~includes~~ a ~~majority~~violation ofcould ~~the~~result ~~Partnership’s~~in 16civil ~~wells~~penalties inup ~~the Wattenberg~~to ~~field~~$10,000 per day. The ~~portion~~Managing ofGeneral ~~the settlement relating to the Partnership~~Partner’s ~~wells~~responses ~~for~~were ~~all~~submitted ~~periods~~on ~~through~~February ~~September 30~~6, 2009 ~~that has been expensed by the Partnership is approximately $14~~,~~000~~ ~~including~~and ~~associated~~April ~~legal costs of approximately $1~~8,~~000~~ 2009. ~~This~~Commencing ~~entire~~in ~~settlement~~December ~~of $13~~2009,~~000~~ ~~was deposited by~~ the Managing General Partner ~~into~~entered annegotiations ~~escrow~~with ~~account~~the onCDPHE ~~November~~regarding ~~3, 2008. Notice~~this ofnotice ~~the~~and ~~settlement~~continues ~~was~~to ~~mailed~~work to ~~members~~bring ofthis ~~the~~matter ~~class action~~to ~~suit~~closure. Given in the ~~fourth~~inherent ~~quarter~~uncertainty ofin ~~2008. The~~administrative ~~final~~actions ~~settlement~~of ~~was approved~~this bynature, the ~~court~~Managing onGeneral ~~April~~Partner 7,is ~~2009. Settlement~~unable ~~distribution checks~~to ~~were~~predict ~~mailed~~the inultimate ~~July~~outcome ~~2009. During~~of ~~September~~this ~~2009,~~administrative ~~all settlement~~action ~~costs~~at ~~were~~this ~~passed~~time ~~through to the Partners~~ and ~~related~~therefore ~~required judicial~~no ~~action~~amounts ~~from~~have ~~the~~been ~~settlement~~recorded ofon the ~~suit~~Partnership’s ~~was~~financial ~~implemented in this distribution~~records.

~~Colorado~~Derivative ~~Stormwater Permit~~Contracts. On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment, related to the stormwater permit for the Garden Gulch Road. The ~~Managing~~Partnership ~~General Partner manages this private road for Garden Gulch LLC. The Managing General Partner~~ is ~~one~~exposed ofto ~~eight~~natural ~~users~~gas ofand ~~this road, all of which are~~ oil ~~and~~price ~~gas companies~~fluctuations ~~operating~~on inunderlying ~~the~~sales ~~Piceance~~contracts ~~region~~should ~~of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among~~ the ~~eight~~counterparties ~~users of the road based upon their respective usage. The Partnership has seven wells in this region. The Notice alleges a deficient and/or incomplete stormwater management plan, failure~~ to ~~implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that~~ the ~~recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The~~ Managing General Partner’s ~~responses~~derivative ~~were~~instruments ~~submitted~~not ~~on February 6, 2009, and April 8, 2009~~perform. No Nonperformance ~~civil~~is ~~penalties~~not ~~have been imposed or requested at this time~~anticipated. ~~Given~~Neither the ~~preliminary stage of this proceeding and the inherent uncertainty in administrative actions of this nature, the~~ Managing General Partner, isnor ~~unable to predict~~ the ~~ultimate~~Partnership, ~~outcome of this administrative action at this time and therefore no amounts~~ have ~~been recorded~~had onany ~~the~~counterparty ~~Partnership’s~~default ~~financial records~~losses.

-14 10 -

Index

PDC 2004-C LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2009

(unaudited)

Derivative Contracts. The Partnership is exposed to oil and natural gas price fluctuations on underlying sales contracts should the counterparties to the Managing General Partner’s derivative instruments not perform. The Managing General Partner has had no counterparty default losses and expects full performance by the counterparties to these agreements in the future.

Note 7−Subsequent Events

The Partnership evaluated the Partnership’s activities subsequent to September 30, 2009, through December 18, 2009 (the date the financial statements were issued), and have concluded that no subsequent events have occurred that would require recognition in the Partnership’s financial statements or disclosure in the notes to the unaudited condensed financial statements.

-15-

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Special Note Regarding Forward Looking Statements

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding PDC 2004-C Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated oil and natural gas production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“MGP’s” or “PDC’s”) strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

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

· risks incident to the operation of natural gas and oil wells;

· future production and development costs;

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

· the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America;

· the effect of natural gas and oil derivatives activities;

· conditions in the capital markets; and

· losses possible from pending or future litigation.

Further, the Partnership urges you to carefully review and consider the cautionary statements made in this report, the Partnership’s annual report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission (“SEC”) on October 26, 2009, (“2008 Form 10-K”), and the Partnership’s other filings with the SEC and public disclosures. The Partnership cautions you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

Overview

PDC 2004-C Limited Partnership engages in the development, production and sale of oil and natural gas. The Partnership began oil and gas operations in August 2004 and currently operates 23 gross (20.23 net) wells located in the Rocky Mountain Region in the state of Colorado. Of the Partnership’s total well count, 22 are producing and one Wattenberg Field well is not producing due to operational issues. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. PDC, on behalf of the Partnership through the D&O Agreement, may enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices ~~could~~tend to be affected by demand factors with a seasonal component.

~~-16-~~The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells, may provide for additional reserve development and production. The Managing General Partner has developed a plan to initiate recompletion activities during 2010. This plan includes notifying investor partners that in October 2010, funds to begin these recompletions will be withheld from future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities. The funds retained which are necessary for the Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not recompleted due to an unfavorable general economic climate or unfavorable commodity price environment, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number of recompletions and the timing of recompletions will be based on the availability of cash withheld from distributions and continued favorable geological information. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. The Managing General Partner will continue to evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion.

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition of the remaining third party investor interests in the limited partnerships which PDC has sponsored, including PDC 2004-C Limited Partnership. These purchases, which PDC has stated it anticipates might occur over the next three years, will be subject to PDC’s having sufficient available capital and the approval by a majority of the investors’ partnership interests, excluding partnership interest owned by PDC, of each respective limited partnership.

If a purchase offer from PDC is proposed and approved by a majority of the Partnerships’ unaffiliated limited partners, it would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership.

- 11 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

The following table ~~sets~~presents ~~forth~~ selected information regarding the Partnership’s results of operations, including production volumes, oil and natural gas sales, average sales prices received, average sales price including realized derivative gains and losses, production and operating costs, depreciation, depletion and amortization costs, other operating income and expenses for the three and nine months ended September 30, 2009, or the current three and nine month periods and the three and nine months ended September 30, 2008, or the prior three and nine month periods.

	Summary of Operating Results
	Three months ended March 31,
	Three months ended September 30,									Nine months ended September 30,
	2010			2009			Change
	2009			2008			Change			2009			2008			Change
Number of producing wells (end of period)		22			22			-
Number of producing wells (end of period)		23			23			*			23			23			*
Production: (1)
Production: (1)
Natural gas (Mcf)		63,239			87,543			-28	%
Oil (Bbl)		12,~~959~~576			2,~~069~~356			-59	%		~~6,172~~			~~6,771~~			-9	%
Natural gas (Mcf)		73,166			82,740			-12	%		232,485			242,511			-4	%
Natural gas equivalents (Mcfe) (2)		78,695			101,679			-23	%
Natural gas equivalents (Mcfe) (2)		84,920			95,154			-11	%		269,517			283,137			-5	%
Mcfe per day		874			1,130
Average Selling Price (excluding realized gain (loss) on derivatives)
Natural Gas and Oil Sales
Oil (per Bbl)	$	59.84		$	105.06			-43	%	$	48.30		$	99.63			-52	%
Natural gas	$	328,295		$	263,802			24	%
Natural gas (per Mcf)		2.43			6.72			-64	%		2.54			7.37			-66	%
Oil		187,262			81,441			130	%
Natural gas equivalents (per Mcfe)		3.47			8.12			-57	%		3.30			8.70			-62	%
Total natural gas and oil sales	$	515,557		$	345,243			49	%
Realized Gain (Loss) on Derivatives, net
Realized Gain on Derivatives, net (3)
Oil derivatives - realized gain (loss)	$	30,838		$	(23,875	)		229	%	$	137,801		$	(75,085	)		*
Natural gas	$	170,095		$	279,740			-39	%
Natural gas derivatives - realized gain (loss)		168,030			66,600			-152	%		633,835			(77,567	)		*
Oil		16,773			64,479			-74	%
Total realized gain (loss) on derivatives, net	$	198,868		$	42,725			*		$	771,636		$	(152,652	)		*
Total realized gain on derivatives, net	$	186,868		$	344,219			-46	%
Average Selling Price (including realized gain (loss) on derivatives)
Average Selling Price (excluding realized gain on derivatives)
Oil (per Bbl)	$	75.58		$	93.52			-19	%	$	70.62		$	88.54			-20	%
Natural gas (per Mcf)	$	5.19		$	3.01			72	%
Natural gas (per Mcf)		4.72			7.52			-37	%		5.27			7.05			-25	%
Oil (per Bbl)		72.69			34.57			110	%
Natural gas equivalents (per Mcfe)		56.8155			83.5740			~~-32~~93	%		~~6.16~~			~~8.16~~			~~-24~~	%
Average cost per Mcfe
Average Selling Price (including realized gain on derivatives)
Production and operating costs (3)	$	1.58		$	2.42			-35	%	$	1.44		$	2.38			-40	%
Natural gas (per Mcf)	$	7.88		$	6.21			27	%
Depreciation, depletion and amortization		4.76			2.82			69	%		4.59			2.93			57	%
Oil (per Bbl)		79.21			61.94			28	%
Revenues:
Natural gas equivalents (per Mcfe)		8.93			6.78			32	%
Oil and natural gas sales	$	294,791		$	772,998			-62	%	$	889,252		$	2,462,203			-64	%
Average Lifting Cost (per Mcfe) (4)	$	1.59		$	1.30			22	%
Realized gain (loss) on derivatives, net		198,868			42,725			*			771,636			(152,652	)		*
Operating costs and expenses:
Unrealized (loss) gain on derivatives, net		(443,498	)		1,406,957			-132	%		(1,353,978	)		544,599			*
Direct costs - general and administrative	$	36,096		$	164,676			-78	%
Total revenues	$	50,161		$	2,222,680			-98	%	$	306,910		$	2,854,150			-89	%
Depreciation, depletion and amortization	$	419,515		$	448,394			-6	%
Operating costs and expenses:
Cash distributions	$	381,143		$	391,179			-3	%
Production and operating costs	$	134,483		$	230,358			-42	%	$	387,615		$	674,984			-43	%
Direct costs - general and administrative		73,977			3,081			*			361,220			18,453			*
Depreciation, depletion and amortization		403,840			268,051			51	%		1,236,456			828,452			49	%
Accretion of asset retirement obligations		2,187			2,068			6	%		6,561			6,204			6	%
Total operating costs and expenses	$	614,487		$	503,558			22	%	$	1,991,852		$	1,528,093			30	%
(Loss) income from operations	$	(564,326	)	$	1,719,122			-133	%	$	(1,684,942	)	$	1,326,057			-227	%
Interest expense		(412	)		-			*			(412	)		-			*
Interest income		6,607			7,927			-17	%		18,382			25,364			-28	%
Net (loss) income	$	(558,131	)	$	1,727,049			-132	%	$	(1,666,972	)	$	1,351,421			-223	%
Cash distributions	$	601,197		$	582,790			3	%	$	1,484,508		$	1,699,338			-13	%

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

_______________

(1)

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

(2)

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

(3) ~~Production~~Amounts ~~costs~~ represent ~~oil~~realized ~~and~~derivative ~~gas~~gains ~~operating~~related ~~expenses~~to ~~which~~natural ~~include~~gas ~~production~~and ~~taxes~~oil sales.

~~-17-~~(4) Production costs represent natural gas and oil operating expenses which include production taxes.

- 12 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

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

MBbl – One thousand barrels

Mcf – One thousand cubic feet

MMcf – One million cubic feet

Mcfe – One thousand cubic feet of natural gas equivalents

MMcfe – One million cubic feet of natural gas equivalents

MMbtu – One million British Thermal Units

Natural ~~gas~~ ~~prices~~Gas ~~rebounded~~and ~~somewhat~~Oil from earlier in 2009, through September 2009. The Partnership continued to experience the depressed natural gas prices from the significant declines in late July 2008 through the end of 2008. While the Partnership’s production decreased to 270 MMcfe for the 2009 nine month period compared to 283 MMcfe for the same 2008 period, a decrease of 5%, the Partnership’s average sales price declined $5.40 per Mcfe, a decrease of 62%. While the significant changes in commodity prices have impacted the Partnership’s results of operations, the Managing General Partner believes that it was successful in managing the Partnership’s operations to reduce the negative impacts of lower prices through the Partnership’s derivative positions. The Partnership’s realized derivative gains for the 2009 nine month period of $0.8 million added an average of $2.86 per Mcfe produced during the 2009 nine month period. At September 30, 2009, the Managing General Partner estimates the net fair value of the Partnership’s open derivative positions to be a net liability of $0.3 million.Sales

~~There were~~The ~~two primary contributors to the~~ $1.0.2 million ~~decrease in oil and gas price risk management~~, ~~net. A~~or ~~decrease~~49% ~~in future prices at September 30, 2009 compared to December 30, 2008 resulted in a $1.9 million~~ increase in ~~unrealized~~ ~~derivative~~total ~~losses. This~~sales ~~was partially offset by a $0.9 million increase in realized derivative gains which resulted from depressed commodity prices~~ for the ~~2009~~2010 ~~nine~~three month period, as compared to the ~~higher prices in the~~ same ~~2008~~ period~~. Unrealized~~ ~~gains~~in ~~and~~2009 ~~losses~~was ~~are non-cash~~primarily ~~items~~a ~~and~~reflection ~~these non-cash charges to the Partnership’s statement~~ of ~~operations~~ ~~will continue to fluctuate with~~ the ~~fluctuation~~significantly inhigher ~~commodity~~average ~~prices until~~sales ~~the~~price ~~positions~~per ~~mature~~Mcfe orof ~~are closed~~93%, at which ~~time~~was ~~they~~partially ~~will~~offset ~~become realized~~by orproduction ~~cash~~volume ~~items. The~~decreases ~~Partnership has elected not to designate any~~ of ~~the~~23% ~~Partnership’s~~on ~~derivative~~an ~~instruments~~Mcfe, asor ~~hedges. Under hedge~~energy ~~accounting~~equivalency basis, ~~changes~~during in the ~~fair~~2010 ~~value~~three ofmonth ~~derivatives~~period ~~less~~compared ~~amounts reclassified~~ to ~~realized gains/losses are shown as other comprehensive income in~~ the ~~statement~~prior ofyear ~~equity and not in the statement of operations~~period. ~~While the~~Average ~~required~~sales ~~accounting~~price ~~treatment~~per ~~of recording all changes in the fair value of derivatives in the statement of operations~~Mcfe, ~~for~~excluding ~~derivatives that are not designated as hedges, may result in significant swings in operating results over~~ the ~~life~~impact of ~~the~~realized ~~derivatives, the combination of the settled~~ derivative ~~contracts and~~gains, ~~the~~was ~~revenue~~$6.55 ~~received~~for ~~from~~ the ~~oil~~current ~~and~~year ~~gas~~quarter ~~sales~~compared ~~at delivery are expected~~ to ~~result~~ in$3.40 afor ~~more predictable cash flow stream than would~~ the ~~sales~~same ~~contracts without~~quarter ~~the~~a ~~associated~~year ~~derivatives~~ago.

The ~~table below,~~increase ~~which~~in ~~demonstrates~~natural gas revenues of 24% contrasts to the ~~markets’~~more ~~expected~~significant ~~volatility~~increase in ~~commodity~~oil ~~pricing, sets~~revenues ~~forth~~of ~~the~~130%. ~~average~~The ~~NYMEX~~Partnership’s ~~and~~oil ~~CIG~~revenue increase was bolstered by improved average oil sales prices ~~for~~(110%) as compared to the ~~next~~more 24moderate, ~~months~~yet significant, increase in natural gas sales prices (~~forward curve~~72%) ~~from~~during the ~~selected dates:~~period.

		June 30,		September 30,		March 31,		September 30,		October 31,
Commodity	Index	2008		2008		2009		2009		2009
Natural gas: (per MMbtu)
	NYMEX	$	12.52	$	8.21	$	5.44	$	6.25	$	6.00
	CIG		8.86		5.46		4.15		5.64		5.49
Oil: (per Bbl)	NYMEX		140.15		103.63		59.35		74.64		81.26

The Partnership expects to experience continued declines in both natural gas and oil production volumes over the wells’ life cycles until such time that the Partnership’s Wattenberg wells may be successfully recompleted. Subsequent to a successful recompletion, production will once again be expected to decline.

~~-18-~~Natural Gas and Oil Pricing

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

The price the Partnership receives for the natural gas produced in the Rocky Mountain Region is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index, and other indices for production delivered to Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in recent months and for two out of the last six months became a slight positive differential, which is inconsistent with historical variances. This negative differential between NYMEX and CIG averaged $1.62 for the three months ended March 31, 2009, and narrowed to an average of $0.16 for the three months ended March 31, 2010. Along with the higher sales price of natural gas liquids, which sales are included in the Partnership’s natural gas sales, the price the Partnership realized exceeded the NYMEX price for the first quarter of 2010.

- 13 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Oil~~Commodity ~~and~~Price ~~Natural~~Risk ~~Gas Sales~~Management, Net

~~Partnership production~~The ~~decreased~~Managing toGeneral 85Partner ~~MMcfe~~uses natural gas and ~~270~~oil ~~MMcfe~~derivative instruments to manage price risk for ~~the~~PDC ~~current~~as ~~year~~well ~~three~~as ~~and nine~~sponsored ~~month~~drilling ~~periods,~~partnerships. Commodity ~~respectively~~price risk management, ~~from~~net 95includes ~~MMcfe~~realized gains and ~~283~~losses ~~MMcfe~~and ~~for~~unrealized changes in the ~~prior~~fair ~~year three~~value ~~and~~of ~~nine~~derivative ~~month~~instruments ~~periods,~~related ~~respectively. The~~to the Partnership’s ~~oil~~natural ~~and~~ gas ~~sales~~and ~~revenue,~~oil ~~excluding~~production. The ~~price~~Managing ~~risk~~General ~~management~~Partner ~~impacts,~~sets ~~for~~these ~~the~~instruments ~~current three~~for ~~and nine month periods~~PDC, ~~decreased~~and ~~from~~ the ~~comparable~~various ~~periods~~partnerships inmanaged ~~2008,~~ by ~~$0.5~~ ~~million and $1~~PDC.6 Derivative ~~million,~~financial ~~respectively,~~instrument ~~substantially~~positions ~~due~~taken toby the ~~significant~~ ~~decline~~Managing inGeneral ~~commodity~~Partner ~~prices~~ on ~~marginally~~the ~~lower~~Partnership’s ~~volumes~~behalf, ofare ~~11%~~specifically ~~and 5%,~~designated ~~respectively. Approximately~~to ~~$0.4~~the ~~million~~Partnership’s ~~and~~production $1volumes.5 See ~~million~~Note of4, ~~the decrease~~Fair inValue ~~oil~~Measurements and ~~natural~~Note ~~gas~~5, ~~sales~~Derivative ~~revenue~~Financial ~~for~~Instruments, to the ~~current~~Partnership’s ~~three~~unaudited ~~month~~condensed ~~and nine~~financial ~~month~~statements ~~periods,~~included ~~respectively,~~in ~~was~~this ~~due~~report, tofor ~~pricing~~additional ~~and~~details ~~$0.1~~on ~~million~~the ~~and~~Partnership’s ~~$0.1 million~~derivative ~~was~~financial ~~due to decreased production, respectively~~instruments.

The ~~Partnership~~ ~~expects~~following totable ~~experience~~presents ~~continued~~the ~~declines~~realized ~~in both oil~~ and ~~natural~~unrealized ~~gas production~~derivative ~~volumes~~gains ~~over~~and ~~the~~losses ~~wells’~~included ~~life~~in ~~cycles~~commodity ~~until~~price ~~such~~risk ~~time~~management ~~that~~gain ~~the Partnership’s Wattenberg wells may be successfully recompleted. Subsequent to a successful recompletion~~(loss), ~~production will once again begin to decline~~net.

Oil and Natural Gas Pricing

	Three months ended March 31,
Commodity price risk management, net	2010			2009
Realized gains
Oil	$	16,773		$	64,479
Natural Gas		170,095			279,740
Total realized gain, net		186,868			344,219

Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized		(173,111	)		(284,070	)
Unrealized gain (loss) for the period		488,037			(91,109	)
Total unrealized gain (loss), net		314,926			(375,179	)
Commodity price risk management gain (loss), net	$	501,794		$	(30,960	)

~~Financial results~~Realized ~~depend~~gains ~~upon~~recognized ~~many~~in ~~factors, particularly~~ the ~~price~~first quarter of ~~oil~~2010 ~~and~~which ~~natural~~total ~~gas and~~$0.2 ~~the~~million, ~~Partnership’s~~are ~~ability~~a toresult ~~market~~of ~~its~~lower ~~production effectively. Oil and~~ natural gas ~~prices~~and ~~are~~oil ~~among~~spot ~~the most volatile of all commodity~~ prices~~. These~~ ~~price~~at ~~variations~~the ~~have~~settlement adate ~~material impact~~compared onto the ~~Partnership’s~~respective ~~financial~~strike ~~results~~price. ~~Oil~~During ~~and~~the ~~natural~~first ~~gas prices~~quarter ~~also~~of ~~vary by region and locality~~2010, ~~depending upon~~ the ~~distance~~Partnership torecorded ~~markets, and~~unrealized ~~the~~derivative ~~supply~~gains ~~and~~of ~~demand relationships in that region or locality~~$0. ~~This~~5 ~~can~~million, ~~be especially true in the Rocky Mountain Region~~$0. ~~The~~6 ~~combination~~million of ~~increased~~which ~~drilling~~was ~~activity~~related ~~and~~to the ~~lack of~~Partnership’s ~~local~~natural ~~markets~~gas ~~have~~positions, ~~resulted~~offset in apart ~~local~~by ~~market~~unrealized ~~oversupply~~losses ~~situation~~on ~~from time to time. Like most producers in~~ the ~~region, the~~ Partnership’s ~~relies~~CIG ~~on major~~basis ~~interstate~~swaps ~~pipeline~~of ~~companies~~$0.1 ~~to construct these pipelines to increase capacity~~million, ~~rendering~~as the ~~timing~~forward ~~and~~basis ~~availability~~differential ofbetween ~~these~~NYMEX ~~facilities~~ and ~~transportation~~ ~~capacity~~CIG ~~beyond~~has ~~the~~continued ~~Partnership’s~~to ~~control~~narrow.

~~The~~During ~~price~~ the ~~Partnership~~first ~~receives~~quarter ~~for~~of ~~the~~2009, ~~natural gas produced in~~ the ~~Rocky~~Partnership ~~Mountain Region~~experienced isrealized ~~based~~gains onand aunrealized ~~variety~~derivative oflosses ~~prices,~~as ~~which primarily includes~~ natural gas ~~sold~~ atand ~~CIG~~oil prices ~~with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices~~declined. The ~~CIG~~net ~~Index,~~unrealized ~~and other~~loss ~~indices~~ for ~~production~~the ~~delivered~~first toquarter ~~other~~of ~~Rocky~~2009 ~~Mountain~~of ~~pipelines,~~$0.1 ~~has historically~~million ~~been~~was ~~less~~comprised ~~than~~of ~~the~~a ~~price~~decrease ~~received~~in ~~for~~fair ~~natural~~value ~~gas~~of ~~produced in~~ the ~~eastern~~ ~~regions,~~Partnership’s ~~which~~CIG isbasis ~~NYMEX~~swaps ~~based~~of $0. ~~This~~3 ~~negative~~million ~~differential~~which ~~has narrowed~~resulted infrom ~~recent~~a ~~months~~steeper ~~and~~decline ~~has~~in ~~even~~NYMEX ~~more~~pricing ~~recently~~relative ~~become~~to ~~a positive differential.~~ CIG ~~was~~pricing ~~$1.79~~that ~~lower~~was ~~than~~partially ~~NYMEX~~offset inby ~~January~~a ~~2009, narrowed to close at~~ $0.372 ~~lower~~million innet ~~October~~unrealized ~~2009~~gain ~~and~~from ~~has~~the ~~more~~Partnership’s ~~recently~~commodity ~~closed at $0~~derivatives.~~02 higher than NYMEX for November 2009.~~

~~Oil~~Realized derivative gains, down 46% from the prior year first quarter, contributed an additional $2.38 per Mcfe to this year’s total revenues. Comparatively, the total per Mcfe price realized, consisting of the average sales price and ~~Gas~~realized ~~Price~~derivative ~~Risk Management~~gains, ~~Net~~increased 32% to $8.93 for the current year quarter from $6.78 for the prior year first quarter.

Natural Gas and Oil Sales Derivative Instruments. The Managing General Partner uses ~~oil~~various ~~and~~derivative instruments to manage fluctuations in natural gas ~~derivative~~and ~~instruments~~oil ~~to manage~~prices. The Partnership has in place a series of collars, fixed price ~~risk~~swaps ~~for~~and ~~PDC~~basis asprotection ~~well~~swaps on a portion of the Partnership’s natural gas and oil production as ~~sponsored~~set ~~drilling partnerships~~forth in the following table. ~~The~~Under the Partnership’s collar arrangements, if the applicable index rises above the ceiling price, the Managing General Partner ~~sets~~pays ~~these~~the ~~instruments~~counterparty; ~~for PDC~~however, ~~and~~if the ~~various~~index ~~partnerships~~drops ~~managed~~below bythe ~~PDC~~floor price, the counterparty pays the Managing General Partner. ~~Prior~~Under tothe ~~September 30~~Partnership’s commodity swap arrangements, ~~2008~~if the applicable index rises above the swap price, asthe ~~volumes~~Managing ~~produced~~General ~~changed~~Partner pays the counterparty; however, if the ~~mix~~index ~~between~~drops ~~PDC~~below ~~and~~the swap price, the ~~partnerships changed~~counterparty onpays athe ~~pro-rata~~Managing ~~basis~~General Partner. ~~Effective~~Under ~~September~~the ~~30,~~Partnership’s ~~2008~~basis protection swaps, ~~PDC changed~~if the ~~allocation~~differential ~~procedure~~widens ~~whereby~~beyond the ~~allocation~~basis ofswap price, then the ~~derivative positions~~counterparty ~~between~~pays ~~PDC~~the ~~and~~Managing ~~each~~General ~~partnership~~Partner; ~~was~~however, ~~set~~if atthe adifferential ~~fixed quantity~~narrows, then the Managing General Partner pays the counterparty. ~~Existing~~Because ~~positions~~the ~~are~~Partnership ~~allocated~~sells ~~based~~all onof ~~fixed~~its ~~quantities for~~physical ~~each~~natural ~~position~~gas and ~~new~~oil ~~positions~~at ~~will~~similar ~~have~~prices ~~specific~~to ~~designations~~the ~~relative~~indexes inherent in the Partnership’s derivative instruments, the Partnership ultimately realizes a price related to its collars of no less than the ~~applicable~~floor ~~partnership~~and no more than the ceiling and, for the Partnership’s commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.

-19 14 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table presents the ~~primary~~Partnership’s ~~composition~~derivative ofpositions ~~“Oil~~in ~~and~~effect ~~gas~~as ~~price~~of ~~risk management~~March ~~loss~~31, ~~net” for the periods described:~~2010.

	Three months ended September 30,						Nine months ended September 30,
		Collars									Fixed-Price Swaps				CIG Basis Protection Swaps
Oil and gas price risk management, net	2009			2008			2009			2008
Commodity/ Index		Quantity (Gas-Mmbtu)			Weighted Average Contract Price						Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at March 31, 2010(1)
Realized gains (losses)
					Floors			Ceilings
Oil	$	30,838		$	(23,875	)	$	137,801		$	(75,085	)
Natural Gas
Natural Gas		168,030			66,600			633,835			(77,567	)
CIG
Total realized gain (loss), net		198,868			42,725			771,636			(152,652	)
10/01 - 12/31/2010			14,818		$	4.75		$	9.45			-	$	-		-	$	-		$	9,621
Unrealized gains (losses)
01/01 - 03/31/2011			22,227			4.75			9.45			-		-		-		-			10,545
Reclassification of realized (gains) losses included in prior periods unrealized		(201,847	)		168,952			(599,692	)		48,823
NYMEX
Unrealized (loss) gain for the period		(241,651	)		1,238,005			(754,286	)		495,776
04/01 - 06/30/2010			-			-			-			51,948		5.55		52,073		(1.88	)		7,681
Total unrealized (loss) gain, net		(443,498	)		1,406,957			(1,353,978	)		544,599
07/01 - 09/30/2010			-			-			-			51,368		5.56		51,361		(1.88	)		(5,527	)
Oil and gas price risk management (loss) gain, net	$	(244,630	)	$	1,449,682		$	(582,342	)	$	391,947
10/01 - 12/31/2010			6,118			5.75			8.30			29,530		6.09		35,551		(1.88	)		(1,092	)
01/01 - 03/31/2011			8,316			5.75			8.30			16,547		6.82		24,863		(1.88	)		(6,341	)
04/01 - 12/31/2011			-			-			-			139,850		6.77		139,850		(1.88	)		(2,421	)
2012-2013			12,198			6.00			8.27			321,898		7.05		334,097		(1.88	)		(98,919	)
Total Natural Gas			63,677									611,141				637,795					(86,453	)
Oil
NYMEX
04/01 - 06/30/2010			-			-			-			1,196		92.96		-		-			10,338
07/01 - 09/30/2010			-			-			-			1,210		92.96		-		-			9,497
10/01 - 12/31/2010			-			-			-			1,210		92.96		-		-			8,930
01/01 - 03/31/2011			-			-			-			522		70.75		-		-			(7,478	)
04/01 - 12/31/2011			-			-			-			1,628		70.75		-		-			(23,879	)
Total Oil			-									5,766				-					(2,592	)
Total Natural Gas and Oil																				$	(89,045	)

~~Realized gains~~(1) ~~recognized~~Approximately in9% ~~the current year three and nine month periods, are a result~~ of ~~lower oil and gas commodity prices at settlement date compared to~~ the ~~respective~~ ~~contract~~fair ~~price. During~~value ~~the~~of ~~current year three month period,~~ the Partnership ~~recorded unrealized derivative losses on the Partnership~~’s ~~CIG~~derivative ~~basis~~assets ~~swaps of $0.2 million, as the forward basis differential between NYMEX~~ and ~~CIG~~all ~~has continued to narrow. During the current year nine month period, the Partnership recorded unrealized derivative losses on its oil swaps~~ of ~~$0.1 million, as~~ the ~~forward strip price of oil increased during the quarter and on the~~ Partnership’s ~~CIG~~derivative ~~basis~~liabilities ~~swaps~~were ofmeasured ~~$0.6~~using ~~million,~~significant ~~due to~~unobservable ~~the~~inputs ~~narrowing~~(Level of3), ~~the~~see ~~negative~~Note ~~differential~~4, ~~between~~Fair ~~NYMEX~~Value ~~and CIG basis~~Measurements, ~~as previously~~to ~~discussed. The Partnership also recorded unrealized losses on~~ the ~~Partnership’s~~accompanying ~~natural~~unaudited ~~gas~~condensed ~~swaps~~financial ofstatements ~~$0.1~~included ~~million as natural gas prices, which had declined~~ in ~~previous~~this ~~quarters, have risen slightly above those price levels reflected in previous forward curves~~report.

~~Oil~~Natural ~~and gas~~Gas ~~price risk management, net includes realized gains~~ and ~~losses~~Oil ~~and~~Production unrealized changes in the fair value of derivative instruments related to the Partnership’s oil and natural gas production. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, to the accompanying unaudited condensed financial statements for additional details of the Partnership’s derivative financial instruments.Costs

~~Oil~~Generally, natural gas and ~~Natural~~oil ~~Gas~~production ~~Sales~~costs ~~Derivative Instruments~~vary with changes in total natural gas and oil sales and production volumes. ~~The~~Property and severance taxes are estimates by the Managing General Partner ~~uses~~based ~~various derivative~~on ~~instruments~~rates determined using historical information. These amounts are subject to ~~manage~~revision ~~fluctuations~~based inon ~~oil~~actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Property and severance taxes vary directly with total natural gas ~~prices~~ and oil sales. ~~The~~Transportation ~~Partnership~~costs ~~has~~vary indirectly ~~place~~with production volumes. Fixed monthly well operating costs increase on a ~~series~~per ofunit ~~collars~~basis as production decreases per the historical decline curve. In addition, ~~fixed~~general ~~price swaps~~oil field services and ~~basis~~all ~~protection~~other ~~swaps~~costs vary and can fluctuate based on aservices ~~portion~~required. These ofcosts ~~the~~include ~~Partnership’s~~water ~~oil~~hauling and ~~natural~~ ~~gas~~disposal, ~~production~~equipment asrepairs ~~set~~and ~~forth~~maintenance, insnow ~~the~~removal ~~following~~and ~~table~~service rig workovers.

For the three months ended March 31, 2010 compared to the same three month period in 2009, natural gas and oil production, on an energy equivalency-20basis, decreased 22,984 Mcfe, or 23%, due to normally-occurring production declines throughout an oil and natural gas well’s production life cycle in addition to Grand Valley Field operational constraints on three Partnership wells. Production and operating costs were moderately lower by approximately $7,000, or 6% due in part, to volume-associated reductions in production taxes, natural gas transportation and lease operating expenses. Although higher commodity valuations increased production taxes during the three months ended March 31, 2010, this increase was partially offset by a downward adjustment to these accrued taxes due to revisions to tax rates by the Colorado tax agencies, of which the Partnership was notified during the first quarter 2010. Production and operating costs per Mcfe were $1.59 for the 2010 three month period compared to $1.30 for the comparable 2009 three month period.

- 15 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

This table identifies the Partnership’s derivative positions related to oil and gas sales activities in effect as of September 30, 2009, on the Partnership’s production. The Partnership’s production volumes for the three months ended September 30, 2009, were 1,959 Bbls of oil and 73,166 Mcf of natural gas.

		Collars								Fixed-Price Swaps				Basis Protection Swaps
		Floors				Ceilings
				Weighted				Weighted				Weighted				Weighted		Fair Value
Commodity/		Quantity		Average		Quantity		Average		Quantity		Average		Quantity		Average		At
Operating Area/		(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		September 30,
Index		Oil-Bbls)		Price		Oil-Bbls)		Price		Oil-Bbls)		Price		Oil-Bbls)		Price		2009(1)
Natural Gas
Rocky Mountain Region
CIG
	4Q 2009		41,135	$	6.67		41,135	$	8.16		15,174	$	9.20		-	$	-	$	166,998
	2010		47,221		6.64		47,221		8.11		22,761		9.20		138,985		1.88		(26,690	)
	2011		22,227		4.75		22,227		9.45		-		-		164,713		1.88		(181,677	)
	2012		-		-		-		-		-		-		173,291		1.88		(178,859	)
	2013		-		-		-		-		-		-		160,806		1.88		(154,068	)
NYMEX
	2010		6,118		5.75		6,118		8.30		126,079		5.62		-		-		(66,614	)
	2011		8,316		5.75		8,316		8.30		44,164		6.96		-		-		1,085
	2012		-		-		-		-		46,404		6.96		-		-		(2,066	)
Total Natural Gas																			(441,891	)
Oil
Rocky Mountain Region
NYMEX
	4Q 2009		-		-		-		-		1,387		90.51		-		-		26,946
	2010		-		-		-		-		4,800		92.96		-		-		88,438
	2011		-		-		-		-		2,150		70.75		-		-		(13,933	)
Total Oil																			101,451
Total Natural Gas and Oil																		$	(340,440	)

(1)Approximately 81% of the total fair value of the derivative instruments was measured using significant unobserved inputs (Level 3 assets and liabilities). See Note 4, Fair Value Measurements, to the accompanying interim unaudited condensed financial statements.

During late October 2009, the Managing General Partner entered into additional NYMEX fixed-price gas swaps (ranging from $6.67 to $7.11 per MMbtu) and NYMEX gas collars (floors ranging from $6.00 to 6.10 and ceiling ranging from $8.27 to $8.60 per MMbtu) covering all monthly periods from November 2010 to December 2013. The Partnership will be allocated positions by the Managing General Partner for MMbtu’s equal to the number of remaining MMbtu’s of CIG basis protection swaps at September 30, 2009 which were not previously covered by NYMEX fixed-price gas swaps or gas collars.

Production and Operating Costs

Generally, production and operating costs vary either with total oil and natural gas sales or production volumes. Property and severance taxes are estimated by the Managing General Partner based on rates determined using historical information. These amounts are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Property and severance taxes vary directly with total oil and natural gas 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. General oil field services and all other costs vary and can fluctuate based on services required. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.

For the nine months ended September 30, 2009 compared to the same period in 2008, oil and natural production, on an energy equivalency-basis, decreased 5%, due to reduced production resulting from intermittent Wattenberg Field’s high pipeline pressure during 2009 in addition to normally-occurring production declines throughout an oil and natural gas well’s production life cycle. Production and operating costs were lower by $0.3 million, or 43%, due to lower commodity valuations which reduced production taxes by approximately $0.2 million and lower lease operating costs of approximately $0.1 million, derived from lower third-party well service fees, cost reduction initiatives implemented by the Managing General Partner and changing production mix from the smaller Wattenberg Field to the larger Grand Valley Field. Production and operating costs per Mcfe were $1.44 for the nine months ended September 30 of 2009 compared to $2.38 for the comparable period in 2008.

-21-

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

For the three months ended September 30, 2009, compared to the same period in 2008, oil and natural gas production declined 11%, for the same reasons noted above. Production and operating expenses were lower by approximately $0.1 million, or 42%, primarily due to the combination of lower commodity valuations that reduced production taxes by approximately $41,000 and lower lease operating costs of approximately $36,000, due to the same factors described, above. Production and operating costs per Mcfe were $1.58 and $2.42 for the three month period ended September 30, 2009 and 2008, respectively.

Direct Costs−General and Administrative

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs ~~increased~~decreased during the three ~~and nine~~ months ended ~~September~~March 3031, ~~2009~~2010, compared to the same period in ~~2008~~2009, by approximately $0.1 million ~~and~~principally ~~$0.3 million, respectively, primarily~~ due to anreduced ~~increase~~billings ~~in professional fees~~ for ~~audit~~professional services ~~principally to complete prior years’ audits~~.

Depreciation, Depletion and Amortization

~~Depreciation, depletion and amortization (~~DD&A) expense ~~results~~related ~~solely~~to ~~from~~natural ~~the depreciation,~~gas ~~depletion~~ and ~~amortization~~oil ofproperties ~~well~~is ~~equipment~~directly ~~and~~related ~~lease~~to ~~costs~~production volumes for the period. For ~~The calculation~~the ofquarter ~~DD&A~~ended ~~expense~~March is31, ~~directly~~2009, ~~related~~the toPartnership’s ~~reserves~~natural gas and ~~production volumes. DD&A~~oil ~~expense~~economically isproducible ~~primarily~~reserve ~~based~~quantities ~~upon~~were ~~year-end~~determined ~~proved developed~~by ~~producing~~valuing ~~oil~~in-ground ~~and~~natural gas ~~reserves. These~~and ~~reserves~~oil ~~are~~resources, ~~valued~~ at the price of ~~oil and~~ natural gas and oil as of December 31, ~~each year~~2008. ~~If prices~~Upon ~~increase,~~adoption of the ~~estimated~~SEC’s ~~volume~~final rule regarding the modernization of oil and gas ~~reserves~~reporting ~~may increase, resulting~~ in ~~a decrease in~~ the ~~rate~~fourth ofquarter ~~DD&A expense per unit~~ of ~~production. If~~ ~~prices decrease~~2009, asthe ~~prices~~Partnership ~~did~~changed ~~from December 31, 2007~~ to ~~December~~a ~~31,~~price ~~2008,~~determined by the ~~estimated~~12-month ~~volumes~~average of ~~oil and gas reserves may decrease resulting in an increase in~~ the ~~rate~~ first-day-of-the-month ~~DD&A~~price ~~expense~~during ~~per~~each ~~unit~~month of ~~production~~ 2009.

The DD&A expense rate per Mcfe increased to $45.7633 ~~and $4.59~~ for the 2010 three ~~and nine~~ month ~~periods~~ ~~ended September 30~~period, ~~2009, respectively,~~ compared to $24.8241 ~~and $2.93~~ during the same ~~periods~~period ~~ended~~in ~~September~~2009 ~~30,~~as ~~2008~~calculated by the respective methodologies described above. The ~~variances~~variance in the per Mcfe rates for the ~~three~~2010 ~~month~~period ~~periods in each year~~ compared to the ~~corresponding~~2009 ~~nine~~period ~~month~~is ~~periods in each year are primarily~~ the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley ~~fields~~Fields, which have significantly different DD&A ~~rates. These~~ ~~increased~~ rates, ~~offset by lower production volumes, resulted~~ in ~~increases~~addition ~~of approximately $0.1 million and $0.4 million, respectively, in DD&A expense for the three and nine months ended September 30, 2009 compared~~ to ~~same periods in 2008. This is primarily~~ the ~~result~~ effects of ~~increases~~reserve inrevisions ~~per Mcfe expense due to lower proved developed reserves~~ at December 31, ~~2008~~2009 compared to December 31, ~~2007,~~2008 ~~offset~~in bywhich ~~production~~proved ~~level decreases~~developed ofproducing ~~11%~~downward ~~and~~revisions 5%in ~~for~~ the ~~three~~Partnership’s ~~and~~Grand ~~nine~~Valley ~~month~~Field ~~periods~~were ~~ended~~partially ~~September~~offset ~~30, 2009~~by ~~compared~~upward toproved ~~the~~developed ~~same~~producing ~~periods~~revisions ~~ended~~in ~~September~~its ~~30,~~Wattenberg ~~2008, respectively~~Field. ~~While~~ ~~production~~DD&A ~~and~~expense ~~overall~~decreased ~~year-end~~moderately ~~reserves~~by ~~are expected~~29,000, toor ~~decline~~6%, ~~gradually~~as ~~year-to-year~~a ~~over~~result of the ~~wells~~Partnership’s ~~remaining~~decrease ~~life cycles,~~in ~~downward~~production ~~revisions~~volumes toof ~~proved~~23% ~~developed~~quarter-over-quarter ~~oil~~that ~~and~~was ~~natural~~partially ~~gas~~offset ~~reserves~~by in the ~~annual 2008 reserve report, resulted in the~~ increased DD&A ~~unit~~expense ~~cost increases~~rate ~~during~~per ~~the three and nine month periods ended September 30~~Mcfe, ~~2009~~explained ~~as compared to the same periods in 2008~~above.

~~Interest Expense~~Capital Resources and Liquidity

The Partnership’s ~~incurred~~primary ~~interest~~sources ~~expense~~ of ~~approximately~~cash ~~$400~~are ~~for~~from funds generated from the ~~three~~sale of natural gas and ~~nine~~ ~~months~~oil ~~ended~~production ~~September~~and ~~30,~~the ~~2009~~realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating cost, ~~related~~general and administrative activities and provide monthly distributions to ~~amounts~~the ~~funded~~Investor byPartners and PDC, the Managing General Partner. Fluctuations in ~~November~~the ~~2008~~Partnership’s operating cash flow are substantially driven by changes in commodity prices, ~~into~~in ~~escrow~~production onvolumes ~~behalf~~and ofin realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership manages this volatility through derivatives. Therefore, ~~which~~ ~~were~~the ~~subsequently~~primary ~~paid~~source toof ~~Colorado~~the ~~Royalty~~Partnership’s ~~Settlement~~cash ~~litigants~~flow infrom ~~July 2009~~operations becomes the net activity between the Partnership’s natural gas and oil sales and realized derivative gains and losses. ~~Interest~~However, ~~rates~~the ~~paid~~Partnership bydoes not engage in speculative positions, nor does the Partnership ~~were~~hold ~~determined~~economic ~~in accordance~~hedges ~~with~~for 100% of the ~~Applicable~~Partnership’s ~~Federal~~expected ~~Interest~~future ~~Rate~~production ~~applicable~~from toproducing ~~Qualified Legal~~wells ~~Settlements~~and ~~under~~therefore ~~Internal~~may ~~Revenue~~still ~~Code~~experience ~~§468B~~significant fluctuations in cash flows from operations. ~~For~~As ~~more information~~of onMarch 31, 2010, the ~~Colorado~~Partnership ~~Royalty~~had ~~Settlement,~~natural ~~see~~gas ~~Note~~and 6,oil ~~Commitments~~derivative positions in place covering 80% of expected natural gas production and ~~Contingencies,~~ to86% of expected oil production for the ~~accompanying~~remainder ~~unaudited~~of ~~condensed~~2010, ~~financial statements~~at an average price of $3.80 per Mcf and ~~Note~~$92.96 2per Bbl, ~~Summary~~ respectively. See Results of ~~Significant~~Operations ~~Accounting~~for ~~Policies,~~further ~~Due~~discussion ~~from~~of ~~(to)~~the ~~Managing~~impact ~~General~~of ~~Partner~~prices ~~– other,~~and ~~net,~~volumes toon sales from operations and the ~~2008~~impact ~~Form~~of ~~10-K~~derivative activities on the Partnership’s revenues.

-22 16 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

~~Interest Income~~The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas and oil production activities and commodity gains (losses). Natural gas and oil production from the Partnership’s existing properties are generally expected to continue a gradual decline over the remaining life of the wells. Therefore, the Partnership expects a lower annual level of natural gas and oil production and, in the absence of significant price increases or recompletions, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners through the remainder of 2010 and beyond. Future cash distributions may also be reduced to fund well recompletions in the Codell formation of the Wattenberg field.

~~Significantly lower~~- ~~interest~~17 rates applied to lower undistributed revenues held by the Managing General Partner, resulted in lower interest income during the three and nine months ended September 30, 2009, compared to the same periods in 2008.-

Liquidity and Capital Resources

Oil and natural gas production from the Partnership’s existing properties, which commenced in fourth quarter 2004 and peaked during the second quarter 2005, declined rapidly through 2006. During 2007, 2008 and through September of 2009 oil and natural gas production declined gradually. Production is expected to continue to decline gradually over the remaining lives of the wells. Therefore, the Partnership may be unable to maintain its current level of oil and gas production and cash flows from operations if commodity prices remain in their current depressed state for a prolonged period beyond 2009. This decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners in 2010 and beyond.

Working Capital

Working capital at September 30, 2009 was $0.7 million compared to working capital of $1.7 million at December 31, 2008. This decrease of $1.0 million was primarily due to a decrease in receivables from oil and gas sales at September 30, 2009 to $0.2 million as compared to $0.4 million at December 31, 2008. In addition, the receivables at September 30, 2009 for realized and short-term net unrealized derivative gains decreased to $0.1 million and $0.2 million, respectively, from the amounts at December 31, 2008 of $0.3 million and $0.8 million, respectively. In September 2009, there was a net reduction of $0.6 million in amounts due from the Managing General Partner as a $0.6 million receivable for over-withheld production taxes related to Partnership production prior to 2007 was collected. In addition, the Partnership settled the obligation for the Colorado Royalty Settlement of approximately $14,000 with the Managing General Partner. For more information on the Colorado Royalty Settlement see Note 6, Commitments and Contingencies to the accompanying interim unaudited condensed financial statements. The net cash impact of these transactions increased distributions by $0.6 million during the quarter.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of oil and gas or environmental protection. These amounts totaled approximately $36,000 for the nine months ended September 30, 2009. The Partnership received an approximately $124,000 refund for unused drilling advances from the Managing General Partner during the nine month period ended September 30, 2009.

-23-

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

Working capital at March 31, 2010 was $0.7 million compared to working capital of $0.5 million at December 31, 2009. This increase of approximately $0.2 million was primarily due to the following changes in accounts receivable balances:

Natural gas and oil receivables increased to approximately $0.4 million as of March 31, 2010, from approximately $0.3 million as of December 31, 2009.

Realized derivative gains decreased to approximately $0.1 million as of March 31, 2010 from approximately $0.2 as of December 31, 2009.

Due to Managing General Partner-other, net, excluding natural gas and oil sales received from third parties and realized derivative gains, decreased $0.1 million as of March 31, 2010.

Cash Flows

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and oil or environmental protection. These amounts totaled approximately $3,000 and $26,000 for the three months ended March 31, 2010 and 2009, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in ~~May~~February 2005 and has distributed $15.28 million through ~~September~~March 3031, ~~2009~~2010. The table below ~~sets~~presents ~~forth~~ the cash distributions to the Managing General Partner and Investor Partners, including Managing General Partner ~~distribution~~distributions relating to limited partnership units repurchased, for the periods described ~~as follows:~~.

Three months ended September 30,
Quarter		Managing				Investor
2009												2008
ended		General Partner				Partners				Total
Managing				Investor								Managing		Investor
March 31,		Distributions				Distributions				Distributions
General Partner				Partners				Total				General Partner		Partners		Total
2010		$	76,228			$	304,915			$	381,143
Distributions				Distributions				Distributions				Distributions		Distributions		Distributions
2009		$	78,236			$	312,943			$	391,179
$	120,240			$	480,957			$	601,197			$	116,558	$	466,232	$	582,790

Nine months ended September 30,
2009						2008
Managing		Investor				Managing		Investor
General Partner		Partners		Total		General Partner		Partners		Total
Distributions		Distributions		Distributions		Distributions		Distributions		Distributions
$	296,902	$	1,187,606	$	1,484,508	$	339,867	$	1,359,471	$	1,699,338

Investor Partner cash distributions include $4,588 and $12,926 during the three and nine months ended September 30, 2009, respectively, and $3,893 and $10,561 during the three and nine months ended September 30, 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by the Managing General Partner.

Cash Flows From Operating Activities

~~The Partnership’s~~Net ~~operations~~cash ~~are~~provided ~~expected~~by tooperating beactivities ~~conducted~~of ~~with~~approximately ~~available funds and revenues generated from its oil and natural gas production activities~~$0. ~~Changes~~4 inmillion ~~cash~~for ~~flow from operations are largely due to~~ the ~~same~~three ~~factors~~months ~~that~~ended ~~affect~~March ~~the~~31, ~~Partnership’s~~2010, ~~net~~is ~~income~~substantially ~~that~~unchanged ~~are~~from ~~more~~cash ~~fully discussed~~provided ~~under~~by ~~Results~~operating ~~of Operations,~~activities ~~excluding~~for the ~~non-cash~~same ~~items~~period ~~depreciation,~~in ~~depletion and amortization and unrealized gains and losses on derivative transactions~~2009. ~~Based~~Significant onchanges ~~current~~in ~~oil and natural gas prices and prices set by derivatives, and~~ the ~~Partnership’s~~components ~~anticipated~~that ~~production,~~comprise ~~the Partnership~~operating ~~expects~~activities ~~positive~~ cash flows ~~from~~include ~~operations for~~ the ~~remainder~~following ~~of 2009.~~:

~~Changes in~~· ~~market~~A prices for oil and natural gas, the Partnership’s production levels, the impact of realized gains and losses on the Partnership’s oil and natural gas derivative instruments and changes in costs are the principal determinants of the level of the Partnership cash flow from operations. Oil and natural gas sales for the nine months ended September 30, 2009 were approximately 64% lower than the same period in the prior year, resulting from a 62% decrease in ~~average~~direct ~~oil~~costs ~~and~~– ~~natural~~general ~~gas prices~~ and aadministrative ~~5% decrease in oil and natural gas production. While a decline in oil and natural gas prices would affect the amount~~ of cash from operations that could be generated, the Partnership has oil and natural gas derivative positions in place, as of the date of this filing, covering 86% of the Partnership’s expected oil production and 76% of its expected natural gas production for the remainder of 2009, at average prices of $900.511 ~~per Bbl and $7.35 per Mcf~~million, ~~respectively. These~~ ~~contracts~~or ~~reduce the impact of price changes on cash provided by operations for a substantial portion of the expected production for the remainder of 2009. However, the remaining 14~~78% ~~and 24% of estimated remaining 2009 oil and natural gas production, respectively, is not subject to the Partnership’s derivative instrument risk management~~; ~~consequently,~~ ~~associated revenues will be directly impacted by changing commodity market prices.~~and

~~The~~· ~~value of~~A ~~the~~decrease ~~Partnership’s current derivatives positions could change based on changes~~ in ~~oil~~commodity ~~and~~price ~~natural~~risk ~~gas~~management ~~futures~~realized ~~markets,~~gains ~~the~~receipts ~~investors’ view~~ of ~~underlying~~approximately ~~oil and natural gas supply and demand trends and changes in volumes produced~~$0. ~~Partnership~~1 ~~oil~~million ~~and~~or ~~natural gas derivatives as of September 30, 2009 are detailed in Note 5, Derivative Financial Instruments to the accompanying interim unaudited condensed financial statements~~24%.

-24-

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Net cash provided by operating activities was $1.5 million for the nine months ended September 30, 2009 compared to $1.7 million during the same period in 2008, a decrease of $0.2 million. Variances between the two periods in cash provided by operating activities were due primarily to the following:

· A decrease in oil and gas sale revenues of $1.6 million, or 64%, accompanied by an increase in direct costs – general and administrative of $0.3 million; and

· An increase in realized oil and gas price risk management, net of $0.9 million and a decrease in production and operating cost of $0.3 million, or 43%.

· A reduction in Due from Managing General Partner – other, net, of $0.6 million in September 2009, due to the Managing General Partner’s $0.6 million payment to the Partnership for over-withheld production taxes and accrued interest thereon related to Partnership production prior to 2007 which was offset by the Partnership’s approximately $14,000 payment to the Managing General Partner for royalty settlement costs. For more information on the Colorado Royalty Settlement see Note 6, Commitments and Contingencies to the accompanying interim unaudited condensed financial statements.

Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in the Partnership’s Annual Report on Form 10-K Supplemental Oil and Gas Information−Unaudited, Net Proved Oil and Gas Reserves and Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves.

Partnership well recompletions in the Codell formation of Wattenberg Field wells, which may provide for additional reserve development and production, generally occur five to seven years after initial well drilling so that well resources are optimally utilized. These well recompletions would be expected to occur based on a favorable general economic environment and commodity price structure. Since borrowing is not permitted by the Limited Partnership Agreement, well recompletion activities will be funded through the retention of revenues and reduction of Partner cash distributions. There are no immediate plans to initiate recompletion activities in the Wattenberg Field wells owned by the Partnership. As the optimal period approaches, the Managing General Partner will re-evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion. However, no assurance can be given that recompletion activities will be feasible or economic.

Commitments and Contingencies

See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements.

~~Recent~~- ~~Accounting Standards~~18 -

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

Critical Accounting Policies and Estimates

The preparation of the accompanying unaudited condensed financial statements, in conformity with accounting principles generally accepted in the United States of America, 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.

The Partnership believes that the Partnership’s accounting policies for revenue recognition, derivatives instruments, fair value measurements, oil and natural gas properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties. There have been no significant changes to these policies or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership’s Form 10-K for the year ended December 31, 2008.

-25-

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Recent Accounting Standards

See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements.

Critical Accounting Policies and Estimates

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

There have been no other significant changes to the Partnership’s critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership’s 2009 Form 10-K, such policies include revenue recognition, derivatives instruments, fair value measurements, natural gas and oil properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Not ~~Applicable~~ applicable.

Item 4T.

Controls and Procedures

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

2008 Material Weakness

As discussed in the Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2008, over transactions that are directly related to and processed by the Partnership, in that the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting. More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties. This material weakness has not been remediated as of September 30, 2009. The 2008 Annual Report on Form 10-K did not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting pursuant to Item 308T (a)(4) of Regulation S-K. Pursuant to Final Order dated October 19, 2009, temporary Item 308T was extended through December 15, 2010. Accordingly, the Partnership will file the attestation report of the Partnership’s independent registered public accounting firm regarding internal control with the Partnership’s Annual Report on Form 10-K as of December 31, 2010.

(a) Evaluation of Disclosure Controls and Procedures

As of ~~September~~ 30March 31, ~~2009~~2010, PDC, as Managing General Partner ~~on behalf~~ of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner'’s management, including ~~its~~the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership'’s disclosure controls and procedures pursuant to Securities Exchange Act ~~Rules~~Rule 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’s Disclosure Committee in an effort to ensure that information required to be disclosed in the SEC reports ~~the~~that ~~Partnership~~we ~~files~~file or ~~submits~~ submit under the Exchange Act isare recorded, processed, summarized and reported, within the time periods specified inby the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including ~~its~~the ~~principal~~Chief ~~executive~~Executive Officer and ~~principal~~Chief ~~financial~~Financial ~~officers~~Officer, as appropriate, to allow timely ~~decisions~~discussion regarding required financial disclosure.

Based ~~upon~~ ~~that~~on the results of this evaluation, the Managing General Partner’s Chief Executive Officer and the Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were ~~not~~ effective as of ~~September~~March 3031, ~~2009 due to the existence of the material weakness described above in 2008 Material Weakness included in this Item 4 (T)~~2010. Because of the nature of the material weakness noted, the Partnership is not able to quantify the dollar amounts of exposure or potential range of the dollar amount of potential revisions to the financial statements, from this material weakness.

(b) ~~Remediation~~ ofChanges ~~Material Weakness~~ in Internal Control over Financial Reporting

PDC, the Managing General Partner, ~~with~~made ~~participation~~no ~~from~~changes ~~the Audit Committee of its Board of Directors, has been addressing the material weakness disclosed~~ in the Partnership’s ~~2008 Annual Report on Form 10-K. The Managing General Partner believes that with effective implementation of planned changes in~~ internal ~~controls~~control over financial reporting ~~outlined~~(as ~~below,~~such ~~that~~term itis ~~will~~defined bein ~~able to~~Rules ~~remediate~~13a-15(f) ~~this~~and ~~known~~15d-15(f) ~~material weakness as~~ of ~~December~~the ~~31, 2009. However,~~Securities ~~this~~Exchange ~~control~~Act ~~weakness~~of ~~will~~1934) ~~not~~during bethe ~~considered remediated~~quarter ~~until~~ended ~~the~~March ~~changes~~31, in2010, ~~internal~~that ~~controls~~have ~~over~~materially ~~financial~~affected ~~reporting~~or are ~~operating~~ ~~effectively~~reasonably ~~for~~likely ato ~~sufficient~~materially ~~period~~affect ~~of time and~~ the ~~Managing~~Partnership’s ~~General Partner~~internal ~~has~~control ~~concluded,~~over ~~through~~financial ~~testing, that these controls are operating effectively~~reporting.

~~The Partnership made the following changes in its internal control over financial reporting (such as defined in Rules 13a~~-~~15(f)~~ ~~and~~19 ~~15d~~-~~15(f) of the Securities Exchange Act of 1934) during the quarter ended September 30, 2009.~~

-26-

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The Partnership developed documentation that describes the business processes and identifies key controls for internal control over financial reporting that will assist the Managing General Partner in adequately assessing the control over financial reporting for the Partnership. In addition, the Partnership developed documentation to adequately assess segregation of duties. The controls and procedures are currently being tested. Testing is expected to be completed by December 31, 2009. At present, the Partnership has not quantified the total cost of this initiative; however the majority of this cost is expected to be paid by the Managing General Partner.

Until PDC, the Managing General Partner, is able to conclude that the Partnership has remediated this known material weakness in internal control over financial reporting, the Managing General Partner will continue to perform additional analysis and procedures in order to ensure that the Partnership’s financial statements contained in its subsequent SEC filings are prepared in accordance with generally accepted accounting principles in the United States.

During the 2009 third quarter, PDC made the following changes in PDC’s internal control over financial reporting (as such defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting:

· Effective July 1, 2009, as part of PDC’s broader financial reporting system, PDC implemented a new partnership investor distribution accounting module to the existing accounting software. PDC has taken the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps included procedures to preserve the integrity of the data converted and a review by the business owners to validate data converted. Additionally, PDC provided training related to the business process changes and the financial reporting system software to individuals using the financial reporting system to carry out their job responsibilities, as well as, those who rely on the financial information. PDC anticipates that the implementation of this module will strengthen the overall systems of internal controls due to enhanced automation and integration of related processes. PDC is modifying the design and documentation of internal control process and procedures relating to the new module to supplement and complement existing internal control over financial reporting. The system changes were undertaken to integrate systems and consolidate information and were not undertaken in response to any actual or perceived deficiencies in PDC’s internal control over financial reporting. Testing of the controls related to these new systems is ongoing and is included in the scope of PDC’s assessment of its internal control over financial reporting for 2009.

The Managing General Partner continues to evaluate the ongoing effectiveness and sustainability of the changes PDC made in internal control over financial reporting, and, as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reporting. Further information regarding the material weakness of the Partnership referenced above may be found in the Partnership’s Annual Report on 10-K for the year ended December 31, 2008 under Item 9A (T), Controls and Procedures − Management’s Report on Internal Control Over Financial Reporting.

-27-

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 1A.

Risk Factors

Not ~~Applicable~~ applicable.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Unit Repurchase Program: Beginning May 2008, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

~~Third quarter~~The ~~2009~~following ~~unit~~table ~~repurchases~~presents byinformation ~~PDC~~about ~~were~~the ~~1.5~~Managing ~~units~~General ~~repurchased~~Partner’s atlimited anpartner ~~average price of $6,953 per~~ unit repurchases during ~~August. There~~the ~~were~~three nomonths ~~unit repurchases~~ended ~~during~~March ~~July~~31, ~~or September 2009~~2010.

Other Repurchases: Individual investor partners periodically offered and PDC repurchased, units on a negotiated basis before the third anniversary of the date of the first cash distribution.

			Average Price
	Total Number of		Paid per
Period	Units Repurchased		Unit

January 1−31, 2010		2.25	$	6,406
February 1−28, 2010		-		-
March 1−31, 2010		-		-
Total first quarter Unit Repurchase Program repurchases		2.25

~~Items~~Item 3,. 4Defaults ~~and~~Upon 5Senior ~~have been omitted as there is nothing to report.~~Securities

~~-28-~~Not applicable.

Item 4.

[Removed and Reserved]

Item 5.

Other Information

Not applicable.

- 20 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.

Exhibits

(a)	Exhibit Index.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

3.1

Limited Partnership Agreement

10-K

000-51220

3.1

08/05/2009

3.2

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

10-K

000-51220

3.2

08/05/2009

10.1

Drilling and operating agreement between the Partnership and PDC, as Managing General Partner of the Partnership

10-K

000-51220

10.1

08/05/2009

31.1

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

31.2

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

32.1

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

-29 21 -

Index

PDC 2004-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PDC 2004-C Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By: /s/ Richard W. McCullough Richard W. McCullough Chairman and Chief Executive Officer ~~December~~May 1814, ~~2009~~2010

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	~~Date~~
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	May 14, 2010	~~December 18, 2009~~
Richard W. McCullough	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	May 14, 2010	~~December 18, 2009~~
Gysle R. Shellum	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	May 14, 2010	~~December 18, 2009~~
R. Scott Meyers	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal accounting officer)

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